bluuebunny/crossref_metadata_2025 huggingface dataset:
Certification for Interoperability: a Behavior-Driven, Automated Testing Program for WITSML Version 1.4.1 Servers
Authors: Deeks Nigel , Bye Craig , Gidh Yashodhan , Guterman Jose , Metelskyy Denys , Riegel Bill , Lie S. Steinsbø , Magsipok John , Marcotte Donna
Published: June 2014

The Wellsite Information Transfer Standard Markup Language (WITSML) was developed to provide a common data- exchange format, so that drilling data can be used confidently in various domain/business tasks such as drilling optimization, formation evaluation, or safety-related operations, such as real-time pore pressure analysis. WITSML consists of XML data- object definitions and a Web service specification that allow client software applications to store and retrieve information to/from WITSML servers.

A key requirement for interoperability is for WITSML servers to behave consistently in how they interpret and processes data. To help ensure interoperability, certification for WITSML servers has been available for several years. However, for various reasons, these certification processes were not widely adopted, and inconsistency in WITSML server behavior exists.

A new, behavior-based, fit-for-purpose certification process for WITSML servers (version 1.4.1 and higher) is being developed to address these issues. Key to this process is an open source testing tool that automates running a suite of tests, which use standard WITSML queries, data-object definitions, and behaviors defined in the WITSML specification. If a server passes all of the required tests, then it is WITSML certified.

A company that wants to have its WITSML server tested and certified may download the test tool, test suite, and associated data to first test its server in its own environment, before submitting to official testing (which is conducted by Energistics, the vendor-neutral organization that stewards the standards development process).

This paper describes how the testing processes and related technology were developed and are being implemented. This transparent process and behavior-based, automated, and repeatable testing are expected to deliver the ease-of-use and reliable results needed to drive certification, ultimately improving the interoperability and data reliability provided by WITSML.

The testing tool, tests, and processes were developed by the Certification Group of the WITSML Special Interest Group, which comprises representatives from service companies and operators.
Simultaneous Multifracture Treatments: Fully Coupled Fluid Flow and Fracture Mechanics for Horizontal Wells
Authors: Wu Kan , Olson Jon E.
Published: June 2014

Successfully creating multiple hydraulic fractures in horizontal wells is critical for unconventional gas production economically. Optimizing the stimulation of these wells will require models that can account for the simultaneous propagation of multiple, potentially nonplanar, fractures.

In this paper, a novel fracture-propagation model (FPM) is described that can simulate multiple-hydraulic-fracture propagation from a horizontal wellbore. The model couples fracture deformation with fluid flow in the fractures and the horizontal wellbore. The displacement discontinuity method (DDM) is used to represent the mechanics of the fractures and their opening, including interaction effects between closely spaced fractures. Fluid flow in the fractures is determined by the lubrication theory. Frictional pressure drop in the wellbore and perforation zones is taken into account by applying Kirchoff's first and second laws. The fluid-flow rates and pressure compatibility are maintained between the wellbore and the multiple fractures with Newton's numerical method. The model generates physically realistic multiple-fracture geometries and nonplanar-fracture trajectories that are consistent with physical-laboratory results and inferences drawn from microseismic diagnostic interpretations.

One can use the simulation results of the FPM for sensitivity analysis of in-situ and fracture treatment parameters for shale-gas stimulation design. They provide a physics-based complex fracture network that one can import into reservoir-simulation models for production analysis. Furthermore, the results from the model can highlight conditions under which restricted width occurs that could lead to proppant screenout.
Modeling Transportation Logistics, Water Use, and Surface Footprint for Shale Gas Field Developments
Authors: Mitschanek Mathias , Thonhauser Gerhard , Prohaska Michael
Published: June 2014

Optimizing operational efficiencies in unconventional resource developments is one of the key success drivers for improved economics. In this work, an approach for exactly that problem is presented, designed for a field development scenario in Germany. Starting with a model that captures all key parameters which are influencing a development program such as the gas market and prize scenarios, political situation, environmental regulations, logistical requirements, etc., it immediately turns out that the highly complex model has to be significantly simplified and a sub-model with clear and precise boundary conditions has to be generated. This sub-model is tuned to problems of particular interest, considering technological parameters such as the impact of various state of the art drilling technologies or different fracturing methodologies on the entire development program. It is possible to identify interrelations of various procedures and allows estimating project costs. Operational scenarios can also efficiently be tested, and validated and the financial key parameters of different scenarios can be compared. Moreover, short- and long-term benefits and drawbacks of various solutions can be assessed and optimized. Also, limitations of System Dynamics for that kind of simulation are pointed out, and it is shown how to solve the problem with an Agent Based Modeling approach.
Use of Near Bit Azimuthal Gamma Ray and Inclination Tool Improves Geosteering in CBM Wells, Airth Field, Scotland
Authors: Thwaites Nicholas , Suh Asong
Published: June 2014

Interest in European Coal Bed Methane (CBM), driven by an increasing demand for supplies of natural gas in Europe has been ongoing since the 1990's in the UK, Belgium, Germany, France and Poland.

The nature of Carboniferous age European coals: multiple, thinner coal seams with lower permeability than coals seen in Australia or North America has resulted in a horizontal well or multi lateral wellbore architecture employing geosteering through the coal seams. Use of a conventional directional drilling Bottom Hole Assembly (BHA) in which the Logging While Drilling (LWD) sensors are usually 40ft or more from the drill bit, makes geosteering in structurally complex coals, with changing dip and rolling topography a major challenge. The cost sensitive nature of CBM wells makes the use of geosteering tools such as azimuthal resistivity tools uneconomic.

This paper describes the experience of Dart Energy and its heritage company, Composite Energy, in introducing an instrumented mud motor with a near bit Azimuthal Gamma Ray and Inclination tool as a cost effective geosteering aid on the Airth CBM Field in Central Scotland. The use of an instrumented mud motor enabled Dart Energy to improve geosteering performance, increasing net coal in each geosteered section, near doubling of average Rate Of Penetration (ROP), and reducing the number of time consuming and costly sidetracks.

The improvement in geosteering is a critical part of realising the commerciality of CBM wells producing from thinner, structurally complex Carboniferous age coals found in the UK and Northern Europe.
Shale and Tight Reservoirs: A Possible Geomechanical Control in the Success of Producing Wells, Neuquén Basin, Argentina
Authors: Garcia Mariano N. , Sorenson Federico , Stockman Hernan , Zavala Carlos
Published: June 2014

Many tight and shale-oil gas reservoirs are being explored in Argentina to increase local hydrocarbon production. As known, hydrocarbon resources in the Neuquén basin are massive; however, many are far from being developed to the degree that they can be called resources. Significant work has yet to be done to make this happen.

It is also well known that large areas in the Neuquén basin are under strike-slip stress conditions that may be a strong influence on stimulation effectiveness. After analyzing the production results of several wells and their associated oil/gas fields, a hypothesis was developed that suggests a possible relationship between the tectonic framework and the location of successful wells. This hypothesis might not only explain the productivity results of some wells to Vaca Muerta shale and other tight reservoirs, but also could help in locations of new wells to help reduce investment risks and improve productivity.

This analysis compares aspects from structural geology, petrophysics, and completion descriptions observed in different fields to productivity results. Information included in this paper is sufficient to improve understanding of the conditions for a good or bad well based on this hypothesis; therefore, these lessons can be applied to generate conclusions.
The Uncertainty of Future Commercial Shale Gas Availability
Authors: Rogner Hans-Holger , Weijermars Ruud
Published: June 2014

Numerous top-down resource estimates have indicated that shale deposits hold enormous volumes of methane globally. Until recently detailed delineations of shale gas resources and their production have occurred exclusively in North America. The driving forces and enabling conditions behind the rapid exploitation of shale gas resources in North America are assessed to determine if these are transferable to the rest of world. No two shale deposits are created equal and the mere existence of shale does not guarantee success of future gas production. A formation may hold too little oil or gas — or it may not be brittle enough for fracking to work effectively. The challenge is to find so-called ‘sweet spots’, i.e., plays with high flow rates, once stimulated. The amount of shale gas that can be commercially produced under current and future market conditions is determined by the quantity and thermal maturity of shale's organic content, by regional technology cost, access to transmission pipelines and regional gas price levels. The shale gas rush in North America has caused a precipitous drop in natural gas wellhead prices - from some $11/GJ in 2008 to less than $3/GJ in 2012. A review of the economics of shale gas production indicates that (a) the resource appraisal process for conventional gas resources is unsuitable for unconventional gas resources; (b) field development requires continuous (on-the-go) investment in fracking to stimulate well pressure, and (c) depressed US gas prices currently fail to cover full finding and development costs. Unless well technology improves and completion cost declines rapidly, the maturation process of technically recoverable shale gas resources to proved reserves will be delayed. Time value of money effects undermine the commercial availability of shale gas, particularly in regions where ineffective permitting procedures and slow societal acceptance tend to put additional negative pressure on shale field development speed.
Environmental Stewardship: Lessons for European Unconventional Gas from the United States and Australia
Authors: Wilkinson Paul , von Lany Peter , Lane Alexander
Published: June 2014

Europe is on the cusp of an expansion in the development of unconventional gas resources and many analysts are turning to the United States and Australia to learn lessons from markets at different stages of the development curve. Most attention has been focused on similarities and differences in geology, service industry and gas price whilst consideration of environmental stewardship has been dominated by concerns over the potential environmental and health impacts of hydraulic fracturing. Broader issues of local water security, waste water management and landscape impact have, in contrast, received less attention.

To address these issues, the authors take an alternative look at the European market, using experiences in the United States and Australia to consider the risk management practices, regulatory measures and stakeholder engagement techniques that have achieved greatest success in stimulating the industry whilst at the same time protecting environmental assets. Although the industries in the US and Australia exhibit notable differences to that which may develop in Europe, several overarching observations can be made. The importance of joint-stakeholder working, transparency and carefully defined boundaries of jurisdiction are some of the key factors.

Drawing lessons from these examples and others, the authors conclude by identifying three initiatives essential to the emergence of a viable, publically acceptable and sustainable unconventional gas industry in Europe: Collection of robust and reliable environmental baseline data;Using and communicating sound science; andImplementing collaborative governance.

Failure to implement these initiatives could stifle projects, breed uncertainty, promote conflict with existing industries and the public and potentially, discourage investment. Conversely, by implementing the three recommendations, Europe would be better placed to encourage unconventional gas development in a manner that secures social and economic benefits whilst maintaining high levels of environmental stewardship.
Stimulated Rock Information in Multistage Hydraulic Fracturing Treatment
Authors: Lin Avi , Ma Jianfu
Published: June 2014

This paper presents a mathematical integration process through which all of the important useful information and data related to stimulated rock are properly extracted and embedded so that the total effects of the hydraulic fracturing stimulation are properly presented by the microseismic data detected and collected during the hydraulic fracturing process. A multistage hydraulic fracturing strategy is often used to help maximize the stimulated reservoir volume (SRV). The current analysis is based on chaining the stage results one-by-one. At each stage, the three-dimensional (3D) SRV is constructed based on its observed microseismic events using an enhanced convex hull approach. This algorithm offers both a mathematical approximation of 3D volume and a 3D visualization of the SRV geophysical shape(s). More detailed geometric characteristics are further calculated from the ellipsoid that best fits the constructed SRV, which relies on the acquired microseismic events. The characteristics include length, width, height, and orientation's azimuth of the stimulated rock. Moreover, it forms the basis for calculating the overall SRV using the stage-by-stage approach.

In the advanced phase, this algorithm offers characteristics related to the interaction between multiple stages. The accurate 3D geophysical geometry of the overlapping volume between multiple stages is extracted and is calculated, and the percentage of overlapping volume over the SRV is estimated at each stage. These volume overlapping quantities reveal the potential communication between these stages, indicating the efficiency of hydraulic fracturing efforts and implying the loss of treatment fluid. This algorithm provides the field engineers with several useful aspects: an essential, reliable, and direct compound tool to dynamically visualize the stimulated reservoir geometry and treatment field evolution; a real-time evaluation of the efficiency of a hydraulic fracturing treatment; and parameters to help increase the production of a stimulated reservoir.
Effective Assessment of Resource Plays: Handling Transition Zones
Authors: Stabell Fredrik , Martinelli Gabriele , Stabell Charles
Published: June 2014

Resource plays present unique challenges. These large, continuous accumulations need to be assessed by mapping out variations in risks and prospectivity that divide the resource play fairway into discrete, contiguous segments. For the resources - such as shale gas, shale oil, coal bed methane - the challenge is economic recovery. The assessment challenge is the same: Modeling how the resource play should be explored and exploited. Given the current focus on liquid hydrocarbons, the challenge for shale-based resource plays is assessing the potential for oil in rocks that typically hold both gas and oil. This paper extends earlier work by applying an activity-based model to exploration and exploitation of a shale play. The model segments the play into three types of areas: shale oil, shale gas, and transition areas with uncertain proportions of both shale oil and shale gas. The assessment model also promotes understanding of both the areas and the relative impact of alternative completion solutions. The model generates stochastic performance metrics that capture alternative outcome scenarios, economic returns, and the delivery schedule of production and reserves. The performance metrics support both project-level and portfolio-level decisions related to resource plays. Project-level application is illustrated using data from an Eagle Fordtype resource play.
Mechanical Layering: Implications for Hydraulic Fracturing in an Unconventional Tight Carbonate Reservoir in Abu Dhabi, UAE
Authors: Sirat Manhal , Zhang Xing , Simon Janelle , Vantala Aurifullah , Povstyanova Magdalena
Published: June 2014

The tight-carbonate gas reservoir of Onshore Abu Dhabi, UAE, is characterized by having alternating thin and dense reservoir and none-reservoir units, where hydraulic fracturing is the most effective way to increase the productivity by creating the maximal areal contact with the wellbore. The most significant operational constraint associated with hydraulic fracturing is the containment of the produced hydro-fractures, which might extend beyond the reservoir units. To avoid this problem, which is a function of the mechanical and elastic properties of its reservoir rocks and the type of existing stress regimes, these attributes within the reservoir units and the surrounding cap-rocks should be understood.

The 1D Mechanical Earth Models (MEMs), which involve constructing the three principal in situ stresses' profiles with depth together with the elastic and strength properties of the tight carbonate units with their cap rocks have been carried out using different data along 12 wells such as sonic logs, full-bore microimage(s), and rock mechanics testing.

The results of these twelve 1D MEMs in the field indicate that the three principal in situ stresses' axes swap directions and magnitudes at different depths giving rise to identifying different mechanical bedrocks with different mechanical properties corresponding to different stress regimes (normal and strike-slip) at different depths.

The implications of these results suggest that it is likely that the produced hydraulic fractures are mainly vertical to subvertical under both normal and strike-slip stress regimes. Further, depending on the stress regime, the propagation of the hydraulic fractures would likely be into the horizontal in case of strike-slip regime compared to vertical propagation within the normal stress regime. Further, longer hydro-fractures are expected to be developed in stiffer layers.
Optimizing the Development of Tight Oil Formations
Authors: Aladasani Ahmad , Salehi Saeed , Bai Baojun , Nygaard Runar
Published: June 2014

Substantial hydrocarbon reserves remain trapped in reservoirs that are characterized as tight, oil-wet, and fractured. The aforementioned reservoir characteristics are typical to shale formations, and significantly degrade hydrocarbon recovery efficiency because of well productivity, in addition to reservoir, capillary and sweep displacement efficiencies. In this paper an emphasis is made on identifying the governing reservoir force in tight oil formations at various development stages. The literature review in this paper captures scaling groups for capillary imbibition and several wettability modifiers. This is followed by an analysis, of scaling group limitations and the performance of wettability modifiers. A reservoir simulation model is built to evaluate capillary and viscous effects on oil recovery. Subsequently guidance for optimal reservoir development options is presented.

The optimization of well completion and well stimulation has significant impact on well productivity. It is noticed that there may be trade-off in tight formations between the dominance of viscous forces and the significance of decreasing capillary pressures. Although there is an increase in oil production rate, the cumulative oil production decreases slightly in all water wet conditions. The five well patterns can be categorized into well patterns comprising of three wells (shown in Figures 6a and 6c) and six wells (shown in Figures 6b, 6d and 6e). The highest cumulative oil production is well pattern (Figure 6a) duration 7 months, followed by well pattern (figure 6e) duration 3 months.

Oil-wet reservoirs hold considerable quantities of residual oil. However, during early development commercial quantities of available oil saturation are present in carbonate formations and pose low capillary pressures. Viscous forces govern oil recovery in tight oil formations during the initial stages of development (So >> Sor). Therefore, measures taken to reduce or overcome viscous forces yields higher incremental oil recovery compared with other reservoir forces. The precedence of well patterns should focus on well positioning rather than number of wells and operational expediency in managing draw-downs. Future work will evaluate the use intelligent completion technology to allow selective fractures stages in the horizontal well to undergo surfactant and low salinity water treatment by diffusion process during the well lifetime.
Use of Drilling With Casing Technology to Provide Operational Efficiency in the Vienna Basin
Authors: Sackmaier W.. , Tan M. Z. , McGrath M.. , Montoya C..
Published: June 2014

Drilling with Casing (DwC) technology is an efficient well construction process in which the wellbore is simultaneously cased while being drilled, enabling cementing operations to occur almost immediately after the casing is drilled to its planned setting depth. This technology is proven to mitigate drilling hazards such as lost circulation and wellbore instability as the hazard interval can be isolated in a single trip, reducing or eliminating problematic surge and swab effects seen with conventional drilling methods. An operator in the Vienna Basin is currently increasing operational efficiency saving up to two days per well by implementing DwC methods in the surface intervals in the wells’ basis of design. Using this technology, they have been able to drill 1–2 more wells in the allotted time frame enabling earlier recovery of oil and gas versus using conventional drilling methods. Formation drillability analysis concluded the 470m +/− siltstone, sandstone and clay surface interval could be drilled in a single pass with a 13-3/8-in. × 16-in drillable DwC bit. A fully integrated top drive casing running and drilling system compatible with the drilling rig was used to drive the casing. After cementing, the 13-3/8-in casing shoe track and DwC casin bit were drilled out with a conventional PDC or tri-cone bit, eliminating a dedicated drill out trip. The wells portrayed in this paper used DwC in the surface intervals, allowing the operator to reach the intended surface casing depth requirement. The equipment selection, operation, results, and conclusions will be presented.
Stimulation of Unconventional Naturally Fractured Reservoirs by Graded Proppant Injection: Experimental Study and Mathematical Model
Authors: Keshavarz Alireza , Badalyan Alexander , Carageorgos Themis , Johnson Ray , Bedrikovetsky Pavel
Published: June 2014

The coal permeability declines due to fracture closure during the production and pressure depletion. The recently proposed technique for stimulation of natural coal cleats consists of the injection of microsized high-strength particles into a coal natural fractured system below the fracturing pressure. Coupling this technique with hydraulic fracturing treatment resulted in particles entering cleats under leal-off condition. In the current paper it is shown that the particles must be deposited at specific conditions of the particle-coal repulsion, ensuring the absence of external cake formation.

The new method was successfully validated through laboratory injection of microsized glass particles into fractured coal cores. Application of Derjaguin-Landau-Verwey-Overbeek (DLVO) theory resulted in determination of experimental conditions favourable for particle-particle and particle-coal repulsion; these conditions also immobilize the natural fines. At these conditions, no particle attachment to coal surface and no particle agglomeration were observed, thus the conditions exclude formation damage due to external cake formation, particle attraction to coal rock and fines migration. The previously developed mathematical model was used for determination of the duration of particle injection into a coal core at minimum effective stress. Particle placement resulted in almost three-time increase in coal permeability, thus confirming the mathematical model used.

The curve for well productivity index-vs-stimulation zone radius reaches maximum at some critical value of stimulation radius; the maximum is determined by the mathematical model. Placing particles beyond this critical radius results in reduction of well productivity index, due to significant hydraulic losses experienced by suspension flowing through narrowing cleat apertures during production stage.

Applying the proposed novel technology during hydraulic fracturing treatment leads to improvement in productivity of coal seam gas wells and other unconventional resources (shales, tight gas and geothermal reservoirs) through enhancement of interconnectivity among microfractures around the hydraulically induced fractures.
Sweet Spots: What Are They, Where Are They, How Are They Created and Are They Important Anyway?
Authors: Giles M. R. , Tennant S. H.
Published: June 2014

The term sweet spot means different things to different people, for some it might be the economically attractive part of the play for others the cheapest part to access, while others consider that it is represented by a unique property of the play. Here we define a sweet spot as that portion of the play that has top quartile EUR (Estimated Ultimate Recovery). Such sweet spots are not random but tend to occupy only a small area of the total play. Sweet spots come in two categories, simple and composite. The former are typically the result of stratigraphic or structural features while the later are commonly the result of a combination of different geological factors. For composite sweet spots the recipe that works in one play may be different from that which works in another. The key to capturing the value in a new unconventional play is to capture the sweet spot.
Influence of Effective Pressure on Mudstone Matrix Permeability: Implications for Shale Gas Production
Authors: Mckernan R. E. , Rutter E. H. , Mecklenburgh J.. , Taylor K. G. , Covey-Crump S. J.
Published: June 2014

Permeabilities (k) of Lower Jurassic Whitby Mudstone samples collected from a wave-cut platform, NE England, were measured for flow of argon parallel and perpendicular to bedding across a range of effective pressures (peff) (10–70 MPa) using the oscillating pore pressure method. Petrographic analyses including X-Ray diffraction and scanning electron and optical microscopy show that samples comprise a silt-rich, clay bearing mudstone containing <2% organic matter, with measured porosities ranging between 6–9%. An anisotropic fabric is indicated by elongate clay rich lenses and oriented micas, weakened in some layers by bioturbation. Permeability parallel to this layering was measured to be 2–3 orders of magnitude higher than permeability perpendicular, suggesting increased flow-path tortuosity across the layering. Pressure cycling over the range peff = 10–70 MPa was repeated on each sample until a reproducible pattern of permeability variation with peff was observed. Cycling initially reduces the permeability by >2 orders of magnitude, after which permeability of samples parallel to the layering varies with peff according to: k = 4.1(±0.6)×10−19 exp(−0.034 ± 0.003 peff). Over this pressure range volumetric strain measurements showed that after the first pressure cycle pore volume changes are purely elastic and there is no permanent pore collapse. The technique of pressure cycling as part of the measurement of k reduces the time required to make a reliable measurement that is likely to represent the in-situ permeability and its relationship to peff. The impact of permeability sensitivity to pressure was evaluated by application of a simple reservoir model for dry gas. Unless the effective pressure dependent permeability is taken into account, substantial overestimation of gas flow rate and original gas in place will be made from well tests.
Wellbore Stability Estimation Model of Horizontal Well in Cleat-featured Coal Seam
Authors: Ai C.. , Hu C.. , Zhang Y.. , Yu L.. , Li Y.. , Wang F..
Published: June 2014

Lots of cleats, fractures and other weak structures have developed in coal reservoirs, and as a result, there are relatively big difference between its mechanical properties and coal matrix. During the drilling process, the cleats and fractures near the sidewall are more prone to surfer damage than coal matrix under the ground stress, crack stress, fluid pressure and borehole fluid additional stress, and thus destabilizing phenomena such as borehole collapse and circulation loss would take place. This paper used elasticity and fracture mechanics theories, and took the time effect of sidewall rock drilling fluid seepage into consideration to deduct stress intensity factorIandIIat the cleat tip under the action of the fluid-solid coupling, to establish criterion for the failure condition of coal matrix and cleat fractures, and to establish the wellbore stability calculation model for the cleat-featured coal body. Applying the model can calculate the safe drilling fluid density during the drilling process in cleat-featured coal seam, get the influence law of the factors which affect the wellbore stability such as the length of cleats, horizontal inclination of cleats and opening time of borehole, etc, and it also can analyze the time-delay effect of wellbore destabilization during the drilling process in cleat-featured coal seam. The study achievement was the supplement and perfection of the existed estimation model for the wellbore stability of coal seam gas well.
Probabilistic Assessment of World Recoverable Shale Gas Resources
Authors: Dong Zhenzhen , Holditch Stephen A. , McVay Duane A. , Ayers Walter B. , Lee W. John , Morales Enrique
Published: June 2014

Many shales previously thought of as only source rocks are now recognized as self-sourcing reservoirs that contain large volumes of natural gas and liquid hydrocarbons that can be produced using horizontal drilling and hydraulic fracturing. However, shale gas resources and development economics are uncertain, and these uncertainties beg for a probabilistic solution.

Our objective was to probabilistically determine the distribution of technically recoverable resources (TRR) and shale original gas in place (OGIP) in highly uncertain and risky shale gas reservoirs for seven world regions. To assess technically recoverable resources, we used the distribution of recovery factors from shale gas reservoirs. We developed a software, Unconventional Gas Resource Assessment System (UGRAS), which integrates Monte Carlo simulation with an analytical reservoir simulator to establish the probability distribution of OGIP and TRR. We used UGRAS to evaluate the most productive shale gas plays in the United States, including the Barnett, Eagle Ford, Marcellus, Fayetteville, and Haynesville shales, and derived a representative distribution of recovery factors for shale gas reservoirs. The recovery factors for the five shale gas plays follow a general Beta distribution with a mean value of 25%. Finally, we extended the distribution of recovery factors gained from our analyses of shale gas plays in the U.S. to estimate technically recoverable shale-gas resources for the seven world regions. Total technically recoverable shale gas resources are estimated to range from 4,000 Tcf (P90) to 24,000 Tcf (P10).

UGRAS is a robust tool that may be used to evaluate and rank shale-gas resources worldwide. This work provides important statistics for the five most productive shale-gas plays in the United States. Results of this work verify the existence of significant technically recoverable shale gas resources worldwide and can help industry better target its exploitation efforts in shale-gas plays.
Water-Based Environmentally Preferred Friction Reducer in Ultrahigh-TDS Produced Water for Slickwater Fracturing in Shale Reservoirs
Authors: Zhou Jia , Baltazar Marcus , Sun Hong , Qu Qi
Published: June 2014

Currently inverse-emulsion polymers are the most popular friction reducers used in fresh water slickwater fracturing in shale reservoirs. The fluid volumes in fracturing treatments have increased substantially, while water supply has become more of a public concern. Rather than paying to treat and dispose of produced and flowback water, operators would like to reuse it in subsequent stimulation treatments. Produced water, especially from shale plays such as Marcellus and Bakken, is known for its high total dissolved solids (TDS) and high divalent cation content. This poses extreme challenges for current friction reducers because cations hinder the inversion of friction reducers and cause loss of efficiency of friction reduction to below 30%. Treating produced water to the quality suitable for conventional fracturing fluids is time-consuming and often cost-prohibitive.

A salt-tolerant, water-based friction reducer was developed to address the challenges of high-TDS produced water. It was tested in a friction loop in a wide variety of produced water types from Bakken, Marcellus, Permian basin and other shale plays at different temperatures and was found to be highly effective. In a produced water sample with TDS over 300,000 ppm and total hardness as CaCO3 (TH) over 90,000 ppm as representative water, the new polymer hydrates within 10 seconds and gives a friction reduction profile similar to that of current inverse-emulsion friction reducers in fresh water. The fluid is compatible with other common stimulation additives such as scale inhibitors, biocides, clay stabilizers, surfactants, and breakers. The new friction reducer was also field tested in New Mexico using produced water with higher than 250,000 ppm TDS and 50,000 ppm total hardness as CaCO3, and head-to-head comparison with a conventional friction reducer under field conditions showed significant performance improvement in terms of pumping at much higher rates while maintaining much lower surface treating pressure.

This paper will discuss the evolution of the technology and show friction reduction performance in various high-TDS water samples under lab conditions. Successful field test and comparison against conventional friction reducers are presented. The new friction reducer provides the oilfield industry a cost-effective solution of reducing produced water disposal and fresh water demands, thereby ultimately improving environmental impact of well operations.
Estimation of Stimulated Reservoir Volume Using the Concept of Shale Capacity and its Validation with Microseismic and Well Performance
Authors: Ouenes A.. , Bachir A.. , Boukhelf D..
Published: June 2014

The concept of SRV was supposed to represent the reservoir volume affected by the fracing and the proppant placement but end up being used as the microseismic stimulated reservoir volume which is usually a much larger volume. Given this large difference, many authors resorted to creating new concepts of SRV adapted to the problems at hand mainly the estimation of reserves. Most of these new concepts rely on the use of microseismic which still has a lot of issues to resolve before being a standard input in shale reservoir simulation and reserve estimation.

To reduce our dependence on microseismic data which is only available in about 5% of the shale wells, a new workflow based on "hard" G&G data is introduced for the estimation of SRV and its varying rock properties in a reservoir simulator. This new workflow relies on the use of the concept of Shale Capacity which encompasses the four key shale drivers responsible for most of the factors affecting the shale well performance: TOC, Brittleness, Fracture Density and Porosity. The shale capacity is available over the entire 3D reservoir volume and is estimated from well and seismic data.

The SRV varying enhanced permeability is estimated through a linear relationship that links the well test measured (PTA or RTA) permeability with the shale capacity thus providing realistic values to the reservoir simulator. Using appropriate gridding techniques such as the Tartan grid for the SRV cells, nearwellbore effects could be accounted for along with no Darcy effects and gas desorption in the shale reservoir. With these key factors represented in the dynamic model around the well, a Marcellus gas and water rate was successfully matched without the need for any major history matching effort. The resulting gas saturation and pressure distribution indicate that the naturally fractured shale matrix cells do contribute to the reserves which are not limited to the nearwellbore SRV cells where the proppant was successfully placed.
Distribution of Well Performances in Shale Reservoirs and Their Predictions Using the Concept of Shale Capacity
Authors: Ouenes Ahmed
Published: June 2014

Various empirical observations have been made regarding the nature of the distribution of shale productivity and the potential existence of three dependent intervals that seem to separate the uneconomical wells from the average and good wells. The areas of good well productivity exhibit a log normal distribution and seem to be controlled mainly by the natural fracture system. These differences in performance seem to be related mostly to the shale capacity defined as the product of four key shale drivers: TOC, porosity, brittleness, and fracture density. When drilling a shale reservoir, it appears that the Relative Intercepted Shale Capacity (RISC) seems to have a strong correlation with the resulting relative well performance. Consequently, well productivity could be predicted in a relative sense with reasonable accuracy if the 3D shale capacity model is available to the operator. Having such a 3D model available, a shale operator can compute the RISC of his future wells and adjust their landing zone, azimuth and length accordingly to reduce drilling and fracing costs, to achieve the best return on investment and accelerate the time to payout.
Integrated Thermal Gas Production from Methane Hydrate Formation
Authors: Sasaki K.. , Sugai Y.. , Yamakawa T..
Published: June 2014

An integrated thermal system, named "Gas to Wire System", for gas production from methane hydrate (MH) layers and generating electricity has been presented based on a balance of waste heat of power plant and dissociations heat of MH including heating the MH layer with hot water. Firstly, gas production by the depressurization method was discussed based on the heat balance between MH dissociation heat and latent heat generated by decreasing of MH equilibrium temperature. The ideal initial MH saturation, showing the maximum one to get 100% gas recover-factor, was obtained as around 16%, even if 6 MPa depressurization is applied for a MH layer. Thus, the depressurization method may be applied for MH layers with low MH saturation less than 20%. The gas production system by injecting hot water from the plant and MH layers using a pair of dual-horizontal wells were modeled and simulated numerically. In the MH reservoir, a dissociated region flowing hot water between dual-horizontal wells, namely hot water chamber, was generated to produce gas continuously. Numerical simulations on MH gas production by hot water injection into a MH layer at Eastern Nankai Trough have been carried out by STARSTM with a pair of dual-horizontal wells 500m in length drilled in the methane hydrate layer of 20 m in layer thickness. Furthermore, a gas production scheme, which uses flow direction changes with four pairs of dual-horizontal wells in radial arrangement in a MH layer with area of 1 km2 located at Eastern Nankai Trough, has been presented, and its production performance was evaluated by the numerical simulation as the cumulative gas production for 15 years is 1.3× 108 std-m3. Finally, total heat balance of the MH gas production system has been investigated, and the waste heat of power generating plant can provide enough heat to increasing MH layer temperature and MH dissociation.
A Review of the Fundamentals of Shale Gas Evaluations: The Dangers of Effective Porosity and Clay Excess Conductivity Corrections
Authors: Glorioso J. C. , Rattia A.. , Lolley R..
Published: June 2014

This paper addresses the problems identified in current shale reservoir characterization practices. We also provide alternative approaches with relevant reflections on the determination of volumes in-place. It is hoped that this paper will stimulate further discussion on the subject and prompt industry to revise current practices.

It is widely recognized that the accurate estimation of rock properties in unconventional reservoirs such as shales is of paramount importance. These property estimates are used for original fluid in place determination, reconciling recoverable volumes of forecast production, well spacing, completion design and many other applications. By comparison with conventional reservoirs, fluids are present not only in the intergranular porous media but also within the fine texture of the rock matrix (Clays, Kerogen and Micro-Fractures) which usually are only recoverable with the aid of suitable stimulation and completion technologies. This paper questions current engineering practices related with the assumption of unrealistic cut-offs in the petrophysical analyses which in turn may result in dangerously misleading estimates of in place volumes and thus inadequate development decisions being made.

The adsorption capacity of clays has been documented in the literature together with observations on the correlations between the percentages of clay minerals in the rock and Langmuir volume (VL) determined in laboratory measurements of gas content from core samples by means of Langmuir isotherms. Therefore it should be no surprise that clays in shale gas reservoirs are known to adsorb hydrocarbon gases and may contribute to the production when properly stimulated. We therefore recommend that corrections for clay effects should not be arbitrarily applied in the petrophysical analysis of electric logs. The use of a total porosity-total water saturation model will help to avoid shortcomings in total gas in-place determination.

There are additional reasons for the avoidance of clay porosity corrections; these include the fact that we have no reliable method to establish clay conductivity at reservoir conditions and we have no tools capable of differentiating between free gas and adsorbed gas. Both of these problems are limiting factors in the correct selection of porosity and water saturation parameters.

Total porosity and water saturation methods give rise to total gas content estimates using the appropriate volumetric model. Adsorbed gas content estimates may be obtained by correlating geochemical data based on gas content from laboratory experiments (which will include both kerogen and clay contributions) and rock density measured on core and or logs. When total porosity and total water saturation models are properly used in shale gas reservoirs characterization, the amount of free gas will be obtained as the difference between total gas content and adsorbed gas content.
A Conceptual Shale Gas Field Development Plan for the Lower Jurassic Posidonia Shale in The Netherlands
Authors: Godderij Raymond , Harings Michiel , Scheffers Berend , Brolsma Maarten-Jan , Bouw Sander
Published: June 2014

In preparation for potential exploration success in the Lower Jurassic Posidonia shale gas play in The Netherlands, EBN decided to investigate the possibilities and conditions of a commercial shale gas development in the area concerned. To this end, a thorough inventory and cost analysis of all activities, that are needed to develop such a shale gas play, formed the basis for an assessment of the most relevant subsurface & surface as well as commercial conditions for success. Detailed evaluations of cores, logs and ditch cuttings, detailed fracture modeling, production forecasting, planning of wells, well designs, well pads and locations, evacuation routes and project scenarios (single or multiple drilling rigs) formed part of the study.

Apart from the technical and commercial parameters, environmental and legal concerns needed to be addressed. The impact of the industrial activities on the physical and social environment in a densely populated area was mapped. Mitigating/impact reducing opportunities were investigated to assure legal requirements could be met in order to obtain the necessary permits from local, provincial and national authorities and to comply with European rules and regulations.

Study results indicate that economical shale gas development would be feasible in The Netherlands under the applied working assumptions.
New Dynamic Rock Test System to Assist in Planning and Creating Multidirectional Fractures
Authors: Surjaatmadja Jim B. , Looper David W. , Coffman Kenneth R. , Meadows David L.
Published: June 2014

In the oil field, rock testing (beyond standard core analyses) is generally limited to three classes—flow tests to determine the production characteristics of the rock in question, chemical tests to determine reactivity of the rocks, and testing the mechanical qualities of the rock to determine the resistance of the rock to forceful intrusions, such as drilling, perforating, and stimulations. Tests to determine mechanical qualities are mostly limited to static or steady state conditions; for example, Young's moduli and Poisson's ratio measurements, compressive strengths, tensile strengths, or anything that offers easily understood and useful data.

This paper discusses the creation of a new test process in which time is used as an aspect of the rock mechanics science in the oil field. For example, a question such as "how much pressure is required to fracture the rock" is henceforth replaced by a question such as "how long does it take for the rock face to move from point ‘A’ to point ‘B’?" To do so, rock testing facilities must be reformulated to include accurate motion monitors and sound detection for live capturing of events within the rock at accurate time steps, such as microseisms, etc. The paper also discusses the use of this technology to plan and create different methods of fracture stimulating a formation; in particular, creating multidirectional fractures to maximize well production is discussed.