bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stimulated Rock Information in Multistage Hydraulic Fracturing Treatment
Authors: Lin Avi , Ma Jianfu 
Published: June 2014

Abstract
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

Abstract
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

Abstract
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

AbstractSubstantial 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 &gt;&gt; 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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 &lt;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 &gt;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

Abstract
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

Abstract
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

Abstract
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.