bluuebunny/crossref_metadata_2025_split huggingface dataset:
Non-Conventional Plays in Romania: the Experience of OMV Petrom
Authors: Krezsek Csaba , Lange Simon , Olaru Radu , Ungureanu Cristina , Namaz Pervin , Dudus Roxana , Turi Valentin 
Published: March 2012

Abstract
This paper describes the key findings of a regional study that targeted the unconventional potential of exploration assets hold by OMV Petrom in Romania. Three unconventional plays have been evaluated, including the (1) Silurian and (2) the Dogger on the East European Margin (including Moesia), and the (3) Oligocene in Maramures (Pienides). The Silurian shales are at 2-4 km depth in the gas window on Western-Central Moesia. Maturity in most cases has been reached by the Late Paleozoic and it was followed by significant exhumation during the Hercynian Orogeny. The quality of Silurian shale represents a major uncertainty, due to the sparse dataset represented by old wells. The Dogger shales of Northern Moesia are in the oil and gas window under the most external thrusts of the Carpathians at depths that exceed 4 km. The shales have TOC values up to 6 %. Oligocene shales with TOC of up to 10 % in Maramures are in the oil window at depths of less than 2 km. This makes them a very attractive target for shale-oil exploration. However, major setbacks are the complex tectonic structure, rugged topography and large-scale exhumation. Ongoing exploration efforts for non-conventional plays are targeted to define the mechanical properties and the exploration sweet spots in the above mentioned plays, but also assessing the potential of the Late Paleozoic bituminous dolomites of Moesia and other black shales in the Carpathians.
Identifying Fault Activation in Unconventional Reservoirs in Real Time Using Microseismic Monitoring
Authors: Kratz Michael , Hill Andrew , Wessels Scott 
Published: March 2012

Abstract
Identification of fault related microseismicity in hydraulic fracture treatments is crucial to understanding how treatments are stimulating a reservoir. Evaluating b values in combination with event source mechanism provides a reliable and intuitive method for separating fault related microseismic events from standard fracture related events. Typically this analysis is conducted after a treatment is complete and serves as a diagnostic tool to provide possible explanations for reduced production or designing future treatments on nearby wells to avoid an identified fault feature. Being able to identify such features in real time allows the operator to not only identify faults but to stop treatment and avoid these features all together saving time and materials that would otherwise be pumped into an area that doesn’t contribute to the overall stimulation of the reservoir, and could reduce production on the well. When evaluating b-values in real time, a technique that can identify faulting early in the initiation of fault stimulation is crucial for preserving the most resources during treatment.
Cyclic Shut-in Eliminates Liquid-Loading in Gas Wells
Authors: Whitson Curtis Hays , Rahmawati Silvya Dewi , Juell Aleksander 
Published: March 2012

Abstract
This paper presents a method to eliminate production loss due to liquid-loading in tight gas wells. Cyclic shut-in control is a simple production strategy that particularly benefits lower-permeability stimulated wells, including but not limited to shale gas wells.
Comparison is made between a gas well producing (1) in a "ideal" situation where 100% of liquids entering from the reservoir or condensing in the tubing are continuously removed (without shut-ins), (2) in a meta-stable liquid-loading condition with low gas rate, typical of most wells today, and (3) by the proposed strategy of cyclic shut-in control. We show that cyclic shutin control of stimulated low-permeability vertical wells to ultra-low-permeability horizontal multi-fraced wells can produce without ever experiencing liquid loading, and with little-to-no delay of ultimate recovery.
Cyclic shut-in control can be applied to all stimulated, lower-permeability gas wells, from the onset of gas rates that result in liquid-loading. The strategy can also be used for wells which already have experienced a period of liquid-loading, but the expected performance improvement may be less because of near-well formation damage caused by historic liquid-loading – e.g. fresh-water backflow and liquid-bank accumulation. In historically liquid-loading wells, an initial period of liquid removal and/or light stimulation may be needed prior to initiating cyclic shut-in control.
We show that the shut-in period should optimally be as short as operationally possible.
Cyclic shut-in control is shown to work equally well for layered no-crossflow systems with significant differential depletion at the onset of liquid loading.
Minimizing rate and recovery loss of liquid-loading gas wells is of international interest. We believe that cyclic shut-in control will become an industry standard practice for shale gas wells, and should lead to a significant ultimate increase in worldwide gas reserves. The method is extremely simple and requires only a rate-controlled wellhead shut-in device.
Selection Criteria for Tubular Connection used for Shale and Tight Gas Applications
Authors: Teodoriu Catalin 
Published: March 2012

AbstractAn unconventional reservoir poses not only difficulties in producing it economically but also requires constrains about the well construction and tubular selection in order to keep the budget in acceptable limits. The tubular used for well construction and well completion must offer maximum integrity at, if possible, minimum costs for the life of the well. The costs associated with tubular are generated by the steel price plus the connection costs. Use of premium connections may not be justified in all unconventional reservoir applications, but as this study will prove, they offer better solutions when the life if the well is considered.This paper starts with a review of main tight gas fields worldwide and based on the well analysis a general tendency for well completion will be shown. The second part of the work will focus in analyzing casing design criteria used in afore mentioned fields. As a result a comprehensive discussion about casing and coupling selection for unconventional wells will be generated. Premium versus non premium connections will be discussed and their impact on the life of the well will be analyzed.
Identification, Integration and Upscaling of Mudrock Types - A Pathway to Unlocking Shale Plays
Authors: Spaw Joan M. 
Published: March 2012

Abstract
A multidisciplinary approach to shale characterization in a variety of North American gas- and liquids-rich shale plays has lead to improved understanding of the bulk physical, chemical and mechanical properties of these deposits and their geologic history. This effort is leading to successful exploitation of these enigmatic resources. Microfacies analysis of mudrocks provides a platform for upscaling from the "nano" to the regional scale, and results in comprehensive mudrock characterizations.
Microfacies analysis of mudrock types within a select stratigraphic interval in a basin leads to the recognition of mudrock lithofacies. Lithofacies identification allows for calibration of petrophysical models, documentation of basin-specific variations in mudrock composition and microfabrics, the distribution of organic-rich members of these intervals, definition of the mechanical stratigraphy for completion design, and provides the litho-stratigraphic building blocks for predictive sequence stratigraphic models.
Successful exploration and exploitation of mudrocks as resources can be advanced when the recognition of mudrock lithofacies provides a methodical means to tie together the geologic, chronostratigraphic, geochemical and petrophysical data from a diverse spectrum of physical scales and technical disciplines.
Just-In-Time Perforating for Controlled, Cost-Effective Stimulation and Production Uplift of Unconventional Reservoirs
Authors: Angeles Renzo , Tolman Randy , El-Rabaa Wadood , Jackson Shalawn , Nygaard Kris 
Published: March 2012

Abstract
Recent advances in multi-stage stimulation technologies, including open- and cased-hole types, have largely overlooked the advantages of single-zone stimulation due to hardware and cost limitations. In most conventional methods, multiple perf clusters are treated at once using one single frac stage with the expectation that equally-stimulated fractures will be created at each perf cluster within tens and hundreds of feet. This creates over-stimulation in some perf clusters and under-stimulation in others, which unveils the current economic and practical limits of effectively creating fractures where needed, not where it is possible to place them. Other methods use a large number of frac plugs which require additional wireline trips and later need to be drilled out, increasing the total cost and mechanical risk of the completion. As lateral length increases, many operators also face the challenge of not being able to remove all frac plugs due to coiled-tubing depth limitations.
This paper introduces the recent implementation of Just-In-Time Perforating (JITP) in shale gas, unconventional plays. JITP is one of the Multi-Zone Stimulation Technologies (MZST) developed and patented by ExxonMobil over a decade ago and extensively used in vertical and S-shaped wells in the Piceance basin, Colorado, and recently implemented in the XTO Fayetteville Shale, Arkansas. JITP creates multiple single-zone fracture stimulations on a single wireline run using ball-sealer diversion and perforating guns that remain downhole during fracturing. Other key features of this method are the use of less horse power, significant reduction in the number of frac plugs, fewer wireline runs, and added flexibility in water management. This paper describes the technical advantages and business justification for applying JITP in unconventional resources and also provides preliminary results from the performance of the JITP field trials in horizontal wells.
An Environmental Solution to Help Reduce Freshwater Demands and Minimize Chemical Use
Authors: Bryant Jason E. , Haggstrom Johanna 
Published: March 2012

Abstract
New technologies to reduce chemical exposure to personnel and the environment during fracturing operations are at the forefront of research and development efforts. Unconventional reservoir developments require large amounts of fresh water, sometimes up to 5 million gal to complete a well, leading to difficulty in water sourcing in remote locations or regions where droughts are persistent. Several new areas currently under consideration for shale exploration are in environmentally sensitive locations, making the water sourcing for fracturing operations even more critical. Freshwater use needs to be minimized, and a careful examination of current practices should be undertaken to reduce, eliminate, and recycle chemicals wherever possible. Furthermore, fracturing fluids essential for successful stimulation treatment should be comprised of chemicals adhering to environmentally acceptable standards.
Recent developments have allowed one operator to minimize freshwater usage through recycling of their flowback and produced water using electrocoagulation (EC) technology. EC is a water-treatment process that removes colloidal solids through methods of coagulation, electroflotation, and settling. Unlike conventional water-treatment practices, such as reverse osmosis or distillation, EC generates relatively small quantities of waste, while leaving dissolved solids in the water. To ensure enough water was available for fracturing stimulation treatment, fresh make-up water was also used. This freshwater source was treated for bacteria using an ultraviolet (UV) trailer, which minimized the need for biocide on location. In addition, dry-blending technology was used to hydrate the gel without the aid of mineral oils. All of these processes were used to reduce the environmental impact on location.
With increasing public scrutiny and concern over the practice of hydraulic fracturing in environmentally sensitive locations, fluid systems need to follow strict environmental guidelines. A new fluid system was developed with components from the US Code of Federal Regulations Title 21 (CFR 21), or the Generally Recognized as Safe (GRAS) affirmation process. While setting a high precedence by adhering to this environmental benchmark, the fluid performance was not compromised.
Water Management-An Increasing Trend in the Oil and Gas Industry
Authors: Hill Freeman , Monroe Steve , Mohanan Reshmy 
Published: March 2012

AbstractWater plays an essential role in the recovery of oil and gas. Managing subsurface water conformance can maximize hydrocarbon production and reduce operating costs. However, unchecked water can decrease hydrocarbon production, reduce oil and gas recovery, increase costs substantially, and lead to possible well abandonment.In the life of a well it is natural that water will eventually enter into the production stream. It is important to identify the water’s source and reason for the intrusion, and how it is interacting with the wellbore. This knowledge can be used to create an integrated customized solution that fits the needs of the well. An indepth understanding of the reservoir can avoid water problem areas in new infield drilling by the use of advanced navigation and directional systems.Water management is essential to maximizing returns on investment and in controlling costs. There are a variety of technologies available for near-wellbore control and reservoir water conformance. Understanding of the water mechanism followed by proper application is key to reducing excess water production.
Successful Implementations of Tophole Managed Pressure Cementing and Managed Pressure Drilling in the Caspian Sea
Authors: Rajabi M. Mir , Rohde B. , Maguire N. , Stave R. S. , Tapper R. 
Published: March 2012

Abstract
Top-hole drilling in the Caspian Sea has historically been very problematic: severe drilling problems are normal when drilling the 26" top-hole sections conventionally – an unconsolidated, over-pressurized sand stratum in the Shah Deniz Field has been one source of these problems. A narrow pore/fracture pressure window, shallow water flow, dissolved gas percolation and mud losses have resulted in extensive non-productive times and an inability to set casing at the desired depth.
Rate of Penetration (ROP) was excessively limited due to cuttings build-up in the hole as the result of low annular velocity. The pressure increase in the wellbore due to the cuttings loading was sufficient to cause losses to the formation.
A new managed Pressure Drilling (MPD) system, developed for drilling subsea wells, uses proven subsea mud pumps from the Riserless Mud Recovery (RMR) system to adjust fluid level inside the riser to maintain a constant Bottom Hole Pressure (BHP)/constant Equivalent Circulating Density (ECD). This compensates for changes in the wellbore pressure profile that may occur due to standard drilling practices and problems such as cuttings loading and annular frictional pressure loss. This technology, called EC-Drill, is also integrated with a reliable early kick/loss detection system which allows the driller to respond quickly before a situation escalates should influxes or fluid losses occur.
Top-hole cement jobs also have been reportedly unsuccessful under such challenging conditions. Losing cement to the formation, plus the added problems of shallow gas and water influx, have been common elements in such failures. To slove the problem, a closed-loop circulation system was established to provide an excellent level of control over the return at the wellhead, so that wellbore pressure could fall inside the pressure window during placement of cement slurry. This cementing technique, called Managed Pressure Cemeneting (MPC), was successfully used in the Caspian Sea.
This paper covers the principle of EC-Drill and MPC methods as well as field data for successful top-hole drilling and cementing operations.
Evaluation of Results From One Company’s Global Use of Underbalanced Drilling for Tight Gas Exploration and Appraisal Reservoir Characterization
Authors: Elliott Dave 
Published: March 2012

Abstract:
Tight gas reservoirs are often characterized by complex geological and petrophysical systems as well as heterogeneities at all scales. In addition, the operating environment is very challenging and that affects the decisions for data acquisition. The use of salt-saturated or oil based mud systems creates a contrast and uncertainty in the data. Hence, the quality of static log and core data acquired is compromised.
In May of 2008 Shell’s Global Wells and Exploration Management made a strategic commitment for the use of Underbalanced Drilling (UBD) for reservoir characterization on all tight gas exploration and appraisal wells. UBD is unique in that, when properly applied, it completely eliminates any uncertainty of drilling or completion fluid damage from the dynamic gas mobility understanding. Specifically the technology has been used in the exploratory and appraisal campaigns to obtain the direct benefits of characterizing the reservoir while drilling, obtaining the real net productive pay zones of the reservoirs and establish whether open fractures were crossed. UBD has also been used to determine reservoir volumes connectivity and obtaining other important reservoir properties in real time, which helps in calibrating the reservoir models. Gas flowing during UBD has been used to optimize the testing, logging and completion plans that were conducted after drilling each of the exploratory wells.
Since 2008 Shell has successfully deployed UBD for tight gas exploration and appraisal on 10 projects in North America, North Africa, the Middle East and Asia. This paper will evaluate the strategic learning’s from this deployment of UBD. Evaluation scope will include HSE, project delivery issues, reservoir learning’s and changes to sub-surface team’s work flows to exploit the information. Selected project results will be presented to support the evaluation conclusions. Discussions will include a view to the future including how Shell is changing overall tight gas project development with UBD de-risking.
Onshore US MPD Use by an Operator
Authors: Montilva J. , Mota J. , Billa R. 
Published: March 2012

Abstract
In the development of onshore gas fields SWEPI LP (Shell) has encountered margins in which the difference between dynamic ECD and static BHP is the difference between lost circulation and influx. The limits imposed by those conflicting conditions create narrow mud weight windows.
The reasons for the tight pore pressure and fracture gradient windows in these vertical and horizontal onshore HPHT tight gas environments vary. Some are old fields challenged by depletion. In the case of South Texas, the main problem is losses in the production hole due to depletion. The pressure in different zones is often difficult to predict due to complex geology further complicated by years of commingled production without knowing what each zone has contributed. In some of the new shale plays, like the Haynesville, slim hole well plans are used which have problems with low kick tolerance design and unexpected kicks through fractured intervals. These pose unique well control challenges to minimize non productive time. In all of these wells, there is the high cost associated with losing mud and/or constantly changing mud weights to prevent losses or influxes.
To mitigate these potential problems, Shell has recognized the use of the Managed Pressured Drilling (MPD) concept which enables the use of the lowest possible mud weight to drill these challenging wells. By lowering the mud weight and manipulating the annular pressure during drilling, the risk of mud losses and/or quick sudden transitions into over-pressured zones is reduced. There are some direct benefits of drilling with lower mud weight such as higher ROP&apos;s, lower stand pipe pressures and lower circulating temperatures. In addition, there are lower ECD&apos;s and higher pump rates that improve the hole cleaning.
Field trials using a fully-automated MPD solution were performed by Shell in South Texas and North Louisiana Haynesville from late 2010 to mid 2011. This paper describes implementation of a fully automated MPD, small rig foot print system which incorporates a Rig Pump Diverter (RPD) that allows smooth transition from circulating to non-circulating down hole during connection while maintaining continuous rig pump circulation.
Results from the field trials will be documented in the paper. We will show the impact of drilling with lower mud weights on well performance. Additionally, a comparison of vertical and horizontal HPHT wells that were drilled conventionally and wells drilled using MPD will be made showing the effects of drilling with lower mud weights on ROP, down hole circulating temperature, ECD, stand pipe pressure and pump rate.
The Effect of Exercise on Pulpal and Gingival Blood Flow in Physically Active and Inactive Subjects as Assessed by Laser Doppler
Authors: Lobo EC , Nguyen SMT , Pogrel MA 
Published: March 2012

The effects of exercise on pulpal and gingival blood flow are undefined. The autonomic nervous system response suggests that they could increase or decrease with exercise, and they may be independent of each other. This study attempts to answer these questions.

Materials and Methods:
15 “physically active” subjects and 15 “physically inactive” subjects exercised on a treadmill. Laser Doppler recordings of pulpal and gingival blood flow were taken before and after exercise.

Results:
There was a mean increase of approximately 50% in both pulpal (range -66%-+509%) and gingival (-72%- +1022%) blood flow after exercise, with wide variations, with no significant differences between the two groups of subjects.

Conclusion:
Exercise could increase pulpal and/or gingival blood flow as part of the overall increase in cardiac output with exercise, or could decrease pulpal and/or gingival blood flow due to diversion of blood to the somatic muscles during exercise. This study suggests that the former physiological phenomenon usually takes place at both sites,though there were some contradictory results.
Glycemic Control Over 5 Years in 4,900 People With Type 2 Diabetes
Authors: Best James D. , Drury Paul L. , Davis Timothy M.E. , Taskinen Marja-Riitta , Kesäniemi Y. Antero , Scott Russell , Pardy Christopher , Voysey Merryn , Keech Anthony C. ,   on behalf of the Fenofibrate Intervention and Event Lowering in Diabetes (FIELD) Study Investigators
Published: March 2012

OBJECTIVE
Glycemic control in type 2 diabetes generally worsens over time, requiring intensification of therapy. The Fenofibrate Intervention and Event Lowering in Diabetes (FIELD) trial provided the opportunity to observe glycemic control in a real-world setting. We assessed the adequacy of metformin, sulfonylureas, and insulin to maintain glycemic control and their effects on weight.

RESEARCH DESIGN AND METHODS
Diabetes control was measured at baseline and yearly for a median of 5 years in the 4,900 patients from the nonintervention arm of this study allocated to placebo.

RESULTS
Median HbA1c was 6.9% at baseline and increased by an average of 0.22% over 5 years (P &lt; 0.001). Median weight was 86.3 kg at baseline and decreased by 0.4 kg over 5 years (P = 0.002). Baseline therapy was lifestyle measures only in 27%, oral agents without insulin in 59%, and insulin in 14% (7% also taking oral agents). Over 5 years, insulin use increased to 32% (21% also taking oral agents). Use of oral agents remained similar at 56%. Only 2% of patients at baseline and 4% after 5 years were taking oral agents other than metformin or sulfonylureas. Initiation of insulin therapy in 855 patients produced a sustained reduction of HbA1c from a median of 8.2 to 7.7%, with a weight gain of 4.6 kg over 5 years.

CONCLUSIONS
With intensification of traditional therapies, glycemic control deteriorated very little over 5 years in a large cohort of type 2 diabetes. However, the requirement for insulin therapy doubled, at the expense of significant weight gain and risk of hypoglycemia.