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Barree R.D.,Barree and Associates | Gilbert J.V.,Barree and Associates
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2010

For years, uncontrolled fracture heights have been modeled for layered reservoirs using Mode-I tensile failure driven three-dimensional (3D) and pseudo-three-dimensional (P3D) fracture geometry models. In these models stress contrast between layers has been assumed to provide the dominant height containment mechanism. Meanwhile, many of the completion diagnostic tools were revealing more contained fracture heights and were thus being discounted. As more diagnostic tools have been employed, it has become apparent that the frac models may have been incorrectly over-predicting fracture heights in many cases. Mine-backs and post-frac coring revealed more contained fracture heights, as did radioactive tracer logs, treating pressure profiles, fall-off data, production modeling, and the absence of perforated interval communication. This paper will present some of the diagnostic data that support more contained fracture height development. These will include case histories from tight gas sands and shales in which restricted fracture height observations are supported by diagnostic observations. It will also go one-step further, by proposing mechanisms which contribute to fracture height containment. These include poroelasticity, abnormally high "trapped" pore pressure, and complex shear in layered or anisotropic media. It will present some modeling methodologies that place more emphasis on poroelasticity and Mode-II shear failure than current conventional fracture models. The need for investigation, and adoption, of these methodologies will be corroborated by diagnostic data. Copyright 2010, Society of Petroleum Engineers.

Barree R.D.,Barree and Associates | Cox S.A.,PetroEdge Energy III LLC | Miskimins J.L.,Barree and Associates | Gilbert J.V.,Barree and Associates | Conway M.W.,Core Laboratories
SPE Production and Operations | Year: 2015

Extrapolation of conventional paradigms to unconventional reservoirs can lead to disappointment and poor performance. Careful analysis of the reservoir and application of the correct stimulation design are critical when dealing with marginally economic developments. This approach includes adequate characterization of the reservoir and an understanding of the factors that control flow capacity and deliverability. One of the biggest practical problems with unconventionalstimulation- design optimization is estimating post-fracture rate, production decline, and ultimate recovery. Without a realistic prediction of the decline resulting from a given completion, it is impossible to assign value to one design over another and equally impossible to optimize the treatment for whichever goal is sought, either acceleration of recovery or increase in reserves. It is often the first-inadequate reservoir characterization- that leads to the second-unrealistic post-treatment predictions. For instance, assuming that core-derived permeability fully represents the reservoir's total flow capacity or that stimulated reservoir volumes represent the effective producing volumes can lead to incorrect diagnosis of the reservoir capability and, consequently, can lead to an inefficient treatment design. This paper presents methods for production forecasting that give reasonable post-treatment predictions that have been found useful for economic planning. The proposed methodology, backed by field observations and laboratory work, provides an economically viable plan for optimizing lateral length, fracture spacing, and treatment design. The methodology focuses on the post-stimulation effective reservoir volume. Results show that increasing apparent fracture length rarely impacts long-term recovery. Likewise, adding more fractures within the same reservoir volume may increase early-time production rate (initial production) and decline rate, without contacting more reservoir volume or adding to long-term recovery. Such practices lead to acceleration of reserves recovery, which has economic value and should be considered in the design process, but does not increase the ultimate recovery of the well once a sufficient number of contributing fractures are in place. The economically preferred completion designs may be more driven by the net present value derived in the first 5 years of production rather than the ultimate recovery of the well. This early 5-year period represents most of the useful economic life of the well, can be estimated more accurately from early performance, and is a good benchmark for completion optimization. © 2015 Society of Petroleum Engineers.

Taylor R.S.,Halliburton Co. | Barree R.,Barree and Associates | Aguilera R.,University of Calgary | Hoch O.,Hoch and Associates Inc. | Storozhenko K.,KJS and Associates Ltd.
Society of Petroleum Engineers - Canadian Unconventional Resources Conference 2011, CURC 2011 | Year: 2011

If one is repeatedly conducting the exact same completion in the same lithology of the same reservoir, then initial production (IP) rates might be a good indicator of relative long-term well performance or estimated ultimate recovery (EUR). This technique is tempting to use because it is quick and simple, and allows for easy comparison. However, use of this method alone assumes the shape of production decline curves will remain consistent from one well to the next. This method can especially be fallible when different numbers of fractures are placed along a lateral with possibly variable length. In this case, the relation between IP and EUR becomes much less defined. Basing key economic decisions on IP alone can be misleading. This paper examines situations in which IP is not only a poor indicator of ultimate well performance, but in fact shows a reverse correlation. Sizing and spacing of fracturing treatments along a horizontal wellbore as well as vertical placement of the lateral in the zone can all be key variables. In many cases, one can choose high IP or optimized economic return, but not always both. Assuming that high IP equates to greater economic return can be a critical error. It is therefore essential to those involved in well-completion design as well as financial analysts to understand the variables involved as well as their impact. A lack of understanding could lead to poor completion and/or stimulation decisions that could severely impact the return on investment (ROI). Copyright 2011, Society of Petroleum Engineers.

Barree R.D.,Barree and Associates | Conway M.W.,Core Laboratories | Miskimins J.L.,Barree and Associates
Society of Petroleum Engineers - SPE Western North American and Rocky Mountain Joint Meeting | Year: 2014

A common issue in unconventional reservoir completion and stimulation design is the selection of fracture initiation points to effectively contact producible reserves. One solution is to equally space initiation points along the entire well, with the trend being to closer spacing to increase reservoir contact. A second approach is to use some combination of logs in the lateral to selectively complete sections that appear to have better reservoir quality or producing capacity. In areas where the rock properties are relatively consistent in terms of reservoir quality, the two methods may overlap so that uniformly spaced fractures offer the best opportunity to for effective stimulation. In other cases, where sections of the lateral are out of zone, or in identifiably inferior reservoir quality, portions of the lateral may be skipped to decrease overall completion cost. This paper presents a method to use and integrate multiple well logs in both vertical and horizontal wells to identify hydrocarbon bearing intervals (storage) and highly productive zones (possibly "natural" fracture sets) for selective completion. Correlations have been found between acoustic velocity, resistivity, gamma-ray, and porosity logs and core-derived properties such as hydrocarbon saturation and TOC%. These correlations have been expanded to include mud log gas shows and ROP (rate of penetration) to differentiate between matrix and secondary fracture contributions to production. With very little core data it is possible to derive a regional model that predicts TOC% from simple log measurements that are commonly available. The analysis strongly suggests areas of a well that should be primary targets for stimulation, zones that can be bypassed with little economic downside, and sections of the well that should not be considered for zonal isolation such as packer setting points. The method has been applied in many unconventional development areas, including the Marcellus, Utica/Point Pleasant, Wolfcamp/Avalon, Duvernay, Montney, and Eagle Ford with equal success. Results have been confirmed by post-frac production logs in cases where complete data sets are available. Copyright 2014, Society of Petroleum Engineers.

Barree R.D.,Barree and Associates | Miskimins J.L.,Barree and Associates | Gilbert J.V.,Barree and Associates
Society of Petroleum Engineers - SPE Western North American and Rocky Mountain Joint Meeting | Year: 2014

Over the last twenty years, Diagnostic Fracture Injection Tests, or DFIT's, have evolved into commonly used techniques that can provide valuable information about the reservoir, as well as hydraulic fracture treatment parameters. Thousands are pumped every year in both conventional and unconventional reservoirs. Unfortunately, many tests that are pumped provide poor or no results due to either problematic data acquisition or incorrect analysis of the acquired data. This paper discusses common issues and mistakes made while acquiring DFIT data. Guidelines on how to avoid these errors and secure the best possible data are provided including data resolution, pump rates, test duration, and fluid selection. Rules of thumb are provided to estimate the time required to reach fracture closure and establish stable reservoir transients for analysis. The last part of the paper addresses potential (and commonly observed) problems in the analysis of the DFIT. These issues can be magnified in tight gas and shale reservoirs due the long data acquisition times and the subtle pressure transients that can occur. Specific issues that are discussed include poor ISIP data from perforation restriction, loss of hydrostatic head, gas entry and the resulting phase segregation, the use of gelled fluids, and errors in after closure analysis. Copyright 2014, Society of Petroleum Engineers.

Ramurthy M.,Halliburton Co. | Towler B.F.,University of Wyoming | Harris H.G.,University of Wyoming | Barree R.D.,Barree and Associates
Society of Petroleum Engineers - Asia Pacific Unconventional Resources Conference and Exhibition 2013: Delivering Abundant Energy for a Sustainable Future | Year: 2013

Hydraulic fracturing continues to be the primary mechanism to produce hydrocarbons out of unconventional reservoirs like tight gas sands, tight coals and shale reservoirs. Over the last few decades it has been studied extensively. However, all the issues that arise during a stimulation treatment have not been understood correctly, yet, leading to costly trial and error approaches to fix them. Assuming that a majority of the perforations (or sleeves) are open and there are no issues with the stimulation fluids, screen-outs and/or pressure-outs during stimulation treatments in any type of reservoir can be attributed to either high pressure-dependent leakoff (PDL) or high process-zone stress (PZS). With high PDL the end result will be a screen-out if it is not addressed properly. However, with high PZS, it is the first indicator and in conjunction with fracture gradient and local stress environment one can understand the reasons for pressure-outs or screen-outs. With high PZS pressure-outs are more common than screen-outs. The objective of this work is to clearly explain and quantify these reservoir-related issues and once identified present solutions such that screen-outs and pressure-outs can be avoided in refracture and new well treatments. The effect of damage zone and the fluid lag or negative net stress zones and their contribution to the fracture tip effects will be presented. This work will also clearly show that zones that exhibit high PZS (greater than 0.20 psi/ft), irrespective of the formation type, are economically poor producers. The tools for identifying these reservoir-related parameters include a diagnostic fracture-injection test (DFIT) and a grid-oriented fully functional 3D fracture simulator with shear decoupling. The relationship between high PZS and the local stress environments and their contribution to issues during a stimulation treatment are presented based on the analysis of 3000 plus DFIT's from the Rockies. Coal, tight gas sand and shale formations are part of the 3000 plus DFIT dataset presented in this work. Examples from coal and shale formations presented earlier by the author are referred in this work. Finally, guidelines (Ramurthy 2012) are presented such that stimulation treatments in high PZS zones that contribute to poor production can be avoided and high PDL zones that lead to good production can be optimized, thereby saving completion costs. © Copyright 2013, Society of Petroleum Engineers.

Sutton R.P.,Marathon Oil | Cox S.A.,Marathon Oil | Barree R.D.,Barree and Associates
Society of Petroleum Engineers - SPE Tight Gas Completions Conference 2010 | Year: 2010

The production of natural gas from shales traces back to the first well drilled in New York in 1821. Over the past 25 years, access to this resource has grown. Recent advancements in drilling and completion technology has enhanced well production rates and production from shales has increased to where it currently supplies 20% of the gas produced by all gas wells in the United States. Well performance data from these shale plays has been compiled and analyzed to develop insight into these tight reservoirs. These results are compared and contrasted to determine similarities and differences among the plays. Comparisons with classical gas reservoirs and tight gas reservoirs are made to provide additional insight. Copyright 2010, Society of Petroleum Engineers.

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