bluuebunny/crossref_metadata_2025_split huggingface dataset:
Stabilized Well Productivity in Double-Porosity Reservoirs
Authors: Hagoort Jacques 
Published: November 2008

Summary
In this work, we present a simple1 analytical formula for the stabilized productivity index (PI) of an arbitrary well in an arbitrary closed, naturally fractured reservoir that can be modeled as a double-porosity reservoir. The formula relates the PI to the PI of a well in a single-porosity reservoir with permeability equal to the effective fracture permeability of the double-porosity reservoir. We have elaborated this formula for a vertical and a horizontal well in a rectangular reservoir made up of orthogonal matrix blocks. It appears that the double-porosity characteristics, along with reservoir flow capacity and reservoir volume, combine into a single factor, which plays the same role as the familiar skin factor. For small values of this double-porosity skin, well productivity is dominated by fracture permeability; for large values, the controlling parameter is matrix permeability. Inflow-performance relationship (IPR) curves of wells in double-porosity gas reservoirs can be created readily with the help of the new PI formula. An example is included showing the production profiles of a vertical and a horizontal well in a double-porosity gas reservoir with cubes and square pillars as matrix blocks. The results of this work are particularly relevant for the reservoir engineering of naturally fractured gas reservoirs.
What is Stimulated Reservoir Volume (SRV)?
Authors: Mayerhofer M. J. , Lolon E. P. , Warpinski N. R. , Cipolla C. L. , Walser D. , Rightmire C. M. 
Published: November 2008

AbstractUltra-low permeability shale reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. In conventional reservoirs and tight gas sands, single-plane fracture half-length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex network structures in multiple planes are created, the concept of a single fracture half-length and conductivity are insufficient to describe stimulation performance. This is the reason for the concept of using stimulated reservoir volume as a correlation parameter for well performance. The size of the created fracture network can be approximated as the 3-D volume (Stimulated Reservoir Volume or SRV) of the microseismic event cloud. This paper briefly illustrates how the Stimulated Reservoir Volume (SRV) can be estimated from microseismic mapping data and is then related to total injected fluid volume and well performance. While the effectively producing network could be smaller by some proportion, it is assumed that created and effective network are directly related. However, SRV is not the only driver of well performance. Fracture spacing and conductivity within a given SRV are just as important and this paper illustrates how both SRV and fracture spacing for a given conductivity can affect production acceleration and ultimate recovery. The effect of fracture conductivity is discussed separately in a series of companion papers. Simulated production data is then compared with actual field results to demonstrate variability in well performance and how this concept can be used to improve completion design, and well spacing and placement strategies.
Workflow for Stratigraphic Characterization of Unconventional Gas Shales
Authors: Slatt Roger M. , Singh Prerna , Philp R. Paul , Marfurt K. J. , Abousleiman Y. , O'Brien N. R. 
Published: November 2008

Abstract
Because of their fine-grained nature, shales exhibit substantially different reservoir properties than more conventional sandstone and carbonate reservoirs. New ideas and modified methods of reservoir characterization are required to reduce uncertainty in measuring volumetrics, drilling and stimulating a well, and gaining efficient production.
Over the past few years, our studies of unconventional gas shales in the U.S. mid-continent have led to establishing a workflow for stratigraphic characterization that addresses key issues in these unusual reservoirs. Proper characterization is multidisciplinary in nature. It includes (1) characterization of multi-scale sedimentology, litho- and sequence-stratigraphy, biostratigraphy, and geochemistry from cores, (2) relating stratigraphy to log response (including borehole image logs), (3) seismic response, (4) petrophysical and geomechanical properties, and (5) organic geochemistry. In addition, educational opportunities are being provided to university students who can then apply knowledge to petroleum industry careers. The result of this integration has led to better understanding of the evolution of shales and their contained gas, and regional to local mapping of key lithologic or stratigraphic intervals for improved drilling and production.
Impact of Shale Properties on Pore Structure and Storage Characteristics
Authors: Bustin R. M. , Bustin A. M. M. , Cui X. , Ross D. J. K. , Pathi V. S. Murthy 
Published: November 2008

Abstract
Characterising the pore structure of gas shales is of critical importance to establish the original gas in place and flow characteristics of the rock matrix. Methods of measuring pore volume, pore size distribution, and sorptive capacity of shales, inherited from the coalbed methane and conventional reservoir rock analyses, although widely applied, are of limited value in characterising many shales Helium which is routinely used to measure shale skeletal and grain density, permeability and diffusivity, has greater access to the fine pore structure of shale than larger molecules such as methane. Utilizing gases other than He to measure porosity or flux requires corrections for sorption to be incorporated in the analyses. Since the permeability of shales vary by several orders of magnitude with effective stress, methods that do not consider effective stress such as crushed permeability, permeability from Hg porosimetry, and from desorption are of limited utility and may be at best instructional.
For shales investigated to date, clay-rich rocks have higher porosity and permeability than biogenic silica-rich shales or carbonate-rich shales. Shales rich in detrital quartz have higher porosity and permeability than shales rich in biogenic quartz and hence simply knowing the mineralogy of a shale may not be diagnostic. The porosity of most shales is mainly dependent on the degree of pore volume development in pores less than 10 um.
Quantifying total gas in place in shales by much of the industry using coal desorption methods and porosity and water saturation determinations, developed for conventional reservoir rocks, may lead to substantial errors. Canister ‘desorption' methods applied to gas shales routinely captures free and solution gas as well as sorbed gas which, if considered as only sorbed gas, results in a significant overestimation of gas in place. A proprietary method of analyses, referred to as MARIO, results in rigorous total gas in place determinations that avoids errors including those associated with molecular sieving and provides a maximum value of the sorbed gas contribution to total gas.
Modeling Flowback Behavior or Flowback Equals "Slowback"
Authors: Crafton James W. 
Published: November 2008

AbstractClear evidence is becoming available that shows that ultimate gas well performance is extremely sensitive to the early time well production management, during the time often referred to as the "flowback". Early time production management in shale gas wells is even more critical than in so-called traditional tight gas reservoirs. This production management problem is exacerbated by the plasticity of shale reservoirs, the need for extensive natural fracture swarms and the now common practice of multiple fracture stimulations of the long-reach laterals. This paper examines three data sets from actual wells that show the adverse impact of excessive early time flow rates, shut-ins during the early time production and the orientation of the laterals. Through numerical simulation and physical experiments, it becomes clear that the traditional performance metrics are at best misleading.
Using Microseismic Events to Constrain Fracture Network Models and Implications for Generating Fracture Flow Properties for Reservoir Simulation
Authors: Williams-Stroud Sherilyn 
Published: November 2008

Abstract
Microseismic monitoring of hydraulic fracture stimulation treatments has done much to diminish the expectation of engineers and geoscientists that symmetrical bi-wing fractures extending away from the well bore from as a result of the treatment. Mapping of microseismic event locations indicates that more often, zones of high complexity form which suggest multiple rock failure mechanisms could be in play during the stimulation treatment. The complexity of the failure is further complicated, or perhaps explained, by the interaction of the perturbed stresses with existing fractures in the reservoir relative to the unperturbed stress state of the reservoir. Existing fracture planes favorably oriented for shear will fail at lower stresses than are required to create new fractures. Geologic mapping and regional to local in-situ stress information will allow informed interpretation of the resulting microseismicity patterns as well as providing predictive capability for fracturing patterns of treatments in subsequent area wells and production planning. Correlative to the improved fracture mapping is the use of the fracture interpretation as input to fractured reservoir modeling and fractured reservoir simulation. Utilizing microseismicity data not only to constrain location of fractures, but also fracture size, shape and orientation allows creation of improved fractured reservoir models based on geologic concepts and supported by the real time data.
In this paper two examples are presented from a hydraulic stimulation of North American mid-continent wells that were monitored with a surface-based geophone array. The resulting microseismicity patterns in both wells show that the fracture development was strongly influenced by pre-existing discontinuities (fractures or faults), which are easily explained by geologic and in-situ stress analysis. The fracture interpretation and microseismicity data from one example is used to generate a discrete fracture network from which fracture flow properties are created in a geocellular model. The resulting model provides a quantitative framework for production history mapping and reservoir behavior, with hard constraints for the behavior of the dominant fractures in the fracture network.
Increasing Fracture Path Complexity and Controlling Downward Fracture Growth in the Barnett Shale
Authors: King George E. , Haile Luke , Shuss Jim , Dobkins Terrell A. 
Published: November 2008

Abstract
Creating an optimum hydraulic fracture to produce gas from nano-darcy shale uses much different technology than that commonly used in low permeability sandstone or carbonate reservoirs. Potentially productive natural fracture pathways are often present but thought to be seldom open in most shales. Effective stimulation in shales requires that the fracture creates an extensive, interconnected and stable flowing network of these natural fractures within the shale, without penetrating into water bearing zones below the shale. Shale wells capable of producing gas at several million scf/d, require development of a fracture pathway with shale face contact of an estimated five to ten million square feet (about one million square meters). Use of downhole microseismic during fracturing has defined sound patterns that confirm the "fracture flow path" in these stimulated shale wells is actually linking intersecting natural fractures into a network of fractures with a flow path width of several hundred feet. These flow paths often have patterns of fracture growth at right angles to the primary fracture direction. Examples of these right angle secondary fractures and the growth cloud of microseismic events that define the complex fracture network are shown in the paper. During extensive fracturing, downward fracture growth can penetrate the carbonates that are found beneath nearly all gas shales. Fracturing into water-wet lower reservoirs can reduce fracture efficiency and severely limit production by flooding the well with water. Effective methods of curtailing this downward frac growth are absolutely essential. This paper reviews some of the prior work on network or complex fracture work in shale and discusses some of the science behind creating the complex fracture network development. The paper also describes the follow-up work using both RA and chemical tracers that helped optimize the flow paths.
Taken together, the development of a very large contact area in the gas-bearing shale (increased shale complexity) and the control of downward growth of the fractures can lead the effort to economically develop and extend the present edges of the Barnett Shale play.
Production Analysis and Forecasting of Shale Gas Reservoirs: Case History-Based Approach
Authors: Mattar L. , Gault B. , Morad K. , Clarkson C. R. , Freeman C. M. , Ilk D. , Blasingame T. A. 
Published: November 2008

AbstractIn this work we present the current status of production evaluation and prediction for shale gas reservoirs. We focus primarily on the effect of wellbore geometry (vertical vs. horizontal) and fracture stimulation, and consider only relatively simple shale reservoir characteristics. Theoretical production responses from hydraulically-fractured vertical and horizontal wells are first described. Analytical and empirical methods for production data analysis and forecasting of shale reservoirs are then described and demonstrated. The empirical approach used is the recently developed "power-law exponential" rate relation [Ilk, et al (2008b and 2008b)] in addition to the more traditional "hyperbolic" rate relation [Johnson and Bollens (1927)], Arps (1945)]. The analytical methods utilized include production type-curves developed for vertical wells completed in single-porosity, single-phase reservoirs. Finally, numerical approaches for forecasting complex, multifractured horizontal wells are also presented. Two approaches for simulating these complex wells, one simple and the other more rigorous, are provided. In the more rigorous approach, the "compound linear flow regime" concept introduced by van Kruysdijk and Dullaert (1989) is verified.The production analysis methods are applied to field and simulated cases to demonstrate their accuracy and practicality. The empirical power-law exponential method, when applied to both simulated and field cases, is shown to be a reliable method for forecasting shale wells. The analytical (type-curve) methods developed for vertical wells can be useful for analyzing vertical shale wells; when applied to horizontal wells, the resulting estimates of reservoir and fracture properties may be inaccurate. A special case of analysis of a 2-phase shale reservoir is also presented; in this case, the analytical tools developed recently for 2-phase CBM reservoirs [Clarkson, et al (2008)], including 2-phase flowing material balance and type-curves, prove useful.
Marcellus Shale Water Management Challenges in Pennsylvania
Authors: Gaudlip A. W. , Paugh L. O. , Hayes T. D. 
Published: November 2008

Abstract
The management of water resources poses considerable challenges to the Pennsylvania Oil and Gas Industry as it begins to expand the development of the Marcellus Shale. Although the play overlies a seemingly water-rich region the sourcing of fresh water for drilling and completions operations are far from straight forward due to regulatory restrictions. Development companies planning to operate in the state must seek to understand an evolving regulatory landscape that is struggling to create a framework specific to shale gas development. The current regulatory status limits conventional methods of surface water withdrawals from streams and rivers and forces industry to search out alternative water sources from groundwater wells, municipalities, private sources and recycled waters. In addition to the challenge of fresh water sourcing, operators are also limited in the options for disposing waste-waters generated during drilling, flowback and production. The current methodology of pre-treatment and discharge via NPDES permit has a finite capacity which is projected to be insufficient in a short time as the level of drilling activity increases. There is very limited potential for underground injection of fluids into permitted disposal wells and virtually no need for weighted brines for well control. Alternative disposal and recycling options which could potentially process the waste-waters into recycled fresh water and concentrated brine or salt cake are being actively studied by individual operating companies and the industry as a whole.
Economic Evaluation of Shale Gas Reservoirs
Authors: Wright John D. 
Published: November 2008

Abstract
Three 9-square mile areas in the Newark East Field were studied to investigate the economic viability of the Barnett shale gas play. The areas chosen corresponded to the 25th, 50th, and 75th percentiles based on average estimated ultimate recovery per well in the areas. The actual drilling and refrac schedule was used for each area along with actual and forecasted production and today's costs and prices to calculate economics on the 329 wells in the areas. Most of the individual wells are not economic under the assumptions of this study. Of the three areas, only the 75th percentile area was economic when considered as a whole. The results are most sensitive to capital costs and gas prices.
Stimulation and Production Analysis of Underpressured (Marcellus) Shale
Authors: Myers Roger R. 
Published: November 2008

Abstract
EXCO-North Coast's has conducted pilot tests to add incremental reserves in a thin Marcellus through a contrarian approach toward stimulating that shale. In these underpressured Jackson County, West Virginia shale wells, slickwater fracture stimulations were used instead of the more common nitrogen gas or nitrogen foam fluids. The premise for this departure from the standard nitrogen gas or foam treatment was that water, being non-compressible, drives net pressure better in shale stimulations, improving chances of opening other planes of weakness or natural fractures with high pump rates and fluid volumes. Further, there was a sense that the Marcellus shale may not be as sensitive to fresh water as previously thought, at least not in the sense that there are swelling or migrating clays to detrimentally impact production. There still may be concerns about relative permeability effects of water on the shale, water imbibition by the shale, and short and long-term liquids management. Recovering as much stimulation water as fast as possible without damaging the induced fracture's conductivity and keeping the shale perforations dry should be best for gas production. Two wells were drilled to the Marcellus shale. Uphole zones commonly stimulated in a multi-zone same day completion were skipped to allow for a Marcellus only production test. The Reciprocal Productivity Index was used to gauge stimulation effectiveness in one of the wells.
Case Study: The Use of Downhole Control Valves To Sustain Oil Production From the First Maximum Reservoir Contact, Multilateral, and Smart Completion Well in Ghawar Field
Authors: Mubarak S. M. , Pham T. R. , Shamrani S. S. , Shafiq M. 
Published: November 2008

Summary
This paper describes a case study that details the planning, completion, testing, and production of the first maximum reservoir contact (MRC), multilateral (ML), and smart completion (SC) deployment in Ghawar Field, Saudia Arabia.
A well was drilled and completed as a proof of concept. It was set up as a trilateral and was equipped with an SC that encompassed a surface-remotely-controlled hydraulic-tubing-retrievable advanced system coupled with a pressure- and temperature-monitoring system.
SC provides isolation and downhole control of commingled production from the laterals. The well was managed to improve and sustain oil production by eliminating water production by use of the variable-positions flow-control valve. Monitoring the rate and the flowing pressure in real time allowed for optimal well production.
The appraisal and acceptance portions of the completion process were achieved when this well was completed, put on production, and tested. The concept was approved when the anticipated benefits were realized during monitoring of the performance of the well.
Leveraged knowledge from this pilot has provided an insight into SC capabilities and implementation. Moreover, it has set the stage for other developments within Saudi Aramco.
β-Cell Autoimmunity in Pediatric Celiac Disease: The Case for Routine Screening?
Authors: d'Annunzio Giuseppe , Giannattasio Alessandro , Poggi Elena , Castellano Emanuela , Calvi Angela , Pistorio Angela , Barabino Arrigo , Lorini Renata 
Published: November 2008

OBJECTIVE—To evaluate the prevalence of β-cell autoimmunity and the usefulness of a type 1 diabetes screening in patients with celiac disease.
RESEARCH DESIGN AND METHODS—We measured GAD antibodies (GADAs), insulinoma-associated protein 2 antigens (IA-2As), and insulin autoantibodies (IAAs) in 188 young Italian patients with celiac disease (66 male [35.1%]). Mean age at celiac disease diagnosis was 5.4 years (0.5–17.1), and mean celiac disease duration was 4.2 years (0–28.8). Celiac disease was diagnosed by jejunal biopsy after positivity for endomysial and tissue transglutaminase antibody was confirmed.
RESULTS—GADAs were positive in seven patients (3.7%), and IA-2As were positive in two patients. IAAs were negative in all cases. Metabolic evaluation was normal, and no patients developed diabetes during follow-up. There was no significant association among β-cell autoimmunity and sex, age, pubertal stage, family history, or coexistence of other autoimmune disorders; compliance to a gluten-free diet was confirmed.
CONCLUSIONS—Our results showed a low prevalence of β-cell autoimmunity and do not support a precocious screening for β-cell autoimmunity in young celiac disease patients.
Prenatal ultrasonographic diagnosis of axillary cystic hygroma
Authors: Thapa Narayan Bikram , Dangal Ganesh 
Published: November 2008

Cystic hygromas are characterized by single or multiple cysts within soft tissue. They may occur in isolation or may be associated with other congenital malformations and can lead to obstructed labour or neonatal asphyxia. Ultrasonography in the prenatal period can be carried out to diagnose congenital cystic hygromas. Keywords: ultrasonography, cystic hygroma doi:10.3126/njog.v2i1.1478 N. J. Obstet. Gynaecol Vol. 2, No. 1, p. 53 - 55 May -June 2007
Hemoperitoneum from suspected uterine perforation: Nonsurgical management of a case of choriocarcinoma. A case report
Authors: Pradhan Pramila 
Published: November 2008

A case of choriocarcinoma presented as an acute abdomen because of intraperitoneal haemorrhage from uterine perforation, 4 weeks after second and 11 weeks following first suction evacuation with high serum hCG level and metastases to vagina and lungs. Once the uterine perforation occurs following gestational trophoblastic neoplasia, immediate laparotomy has been performed usually followed either by local resection or hysterectomy depending on situation. This case is an exception, which was conservatively managed by chemotherapy, EMA-CO regime successfully with no remission on follow up. Keywords: choriocarcinoma, intraperitoneal haemorrhage, uterine perforation. doi:10.3126/njog.v2i1.1483 N. J. Obstet. Gynaecol Vol. 2, No. 1, p. 71 - 73 May -June 2007