bluuebunny/crossref_metadata_2025_split huggingface dataset:
Dentoskeletal effects produced by removable palatal crib, bonded spurs, and chincup therapy in growing children with anterior open bite
Authors: Insabralde Natalia Martins , de Almeida Renato Rodrigues , Henriques José Fernando Castanha , Fernandes Thais Maria Freire , Flores-Mir Carlos , de Almeida Marcio Rodrigues 
Published: May 2016

ABSTRACT
Objective: To evaluate the dentoskeletal effects of different anterior open bite treatment modalities in children.
Materials and Methods: This cephalometric study assessed changes resulting from different treatment approaches on 77 growing children with anterior open bite. A control group (n = 30) was used for comparison. Lateral cephalograms were available before treatment and after 12 months. The sample was divided into four groups: removable palatal crib associated with a chincup (G1), bonded spurs associated with a chincup (G2), chincup (G3), and nontreated control (G4). Statistical comparisons among the four groups were performed on T1 and the treatment changes using analysis of variance with Tukey's post hoc tests.
Results: No statistically significant changes in skeletal variables were found among the groups, except for lower anterior face height (LAFH) increase in G1. Overall, effects in all of the treated groups were exclusively dentoalveolar. A larger overbite (OB) increase was observed in G1 and G2 when compared with G3 and G4. The maxillary incisors in G1 showed increased palatal tipping, retrusion, and more vertical dentoalveolar development as well as increased lingual tipping among mandibular incisors. There was less vertical development of maxillary and mandibular molars in G3.
Conclusions: A removable palatal crib provided an improvement in OB (97.5%), followed by the bonded spurs (84.5%). Conversely, the chincup-only group did not have positive OB effects.
Mature Field Gas Lift Optimisation: Challenges & Strategies, Case Study of D-field, Malaysia
Authors: Ismail Wan Rokiah , Trjangganung Kukuh 
Published: May 2016

Abstract
As the world's population continues to grow, the energy demand is forecasted to increase directly proportional by 52% in between 2010 to 2035 (OPEC, 2013). With the oil prices predicted to be stable in the long run and expected to be as high as $165 per barrel by 2035, the search for more oil continues (OPEC, 2013). An estimation of 70% world's oil and gas production originates from mature fields with recovery at an average of 35% worldwide (Hull, 2012). This proves that there are still opportunities to recover more through enhanced primary, secondary or tertiary recovery in creating further hydrocarbon flow of a mature field.
Lower reserve with high operating and field redevelopment cost for a tertiary recovery program has deteriorated the economics for a mature field. Developing tertiary recovery for a mature field requires major modification at surface and sub-surfac, leaving the operators with the challenge to maximize recovery under current operating conditions and limited work scope of a primary recovery mainly through artificial lift method such as gas lift in oil wells.
Gas lift has been part of the primary oil recovery ever since the 1800s and the effectiveness has proven to aid the acceleration of oil recovery in a well for centuries (Gas Lift: Wikipedia, 2014). Deterioration in surface equipment and sub-surface well completion condition in a mature field, such as worsening well integrity with leaks and holes, inaccurate production metering, instability of gas compressor availability and efficiency, has resultant in the ineffective of gas lift distribution and injection downhole.
Despite the challenges faced, through prudent technical analysis and effective execution at site, the production of D-field in Malaysia has managed to increase up to 8,000 bbl/d (barrel of oil per day) instantaneously merely through production and gas lift optimization exercise.
This paper will run through the challenges faced and the technical analysis conducted in overcoming the handicap at site. This has led to the successful implementation/formulation of production philosophy and strategy to overcome challenges under different production scenarios, resulting an instantaneous production gain of some 30%. To some extent the production has been sustained and the decline arrested.
Chasing New Deep Play in South Malay Basin
Authors: Mohamad Firdaus , Abdullah Muhammad Shahril , Kahar Ruszaidi 
Published: May 2016

Abstract
Malay Basin is a relatively matured basin which has undergone exploration and production for more than three decades, mainly from stratigraphic units of Miocene to Late Oligocene. The matured nature of the basin has driven PETRONAS to evaluate the remaining deep play potentials.
DD is a deep prospect below D Field. Several pre-drill risks were identified during prospect maturation namely, high temperature (450F), high pressure (11000 psi) and poor reservoir quality with low porosity (6% to 12%) and low permeability of &lt;1 mD. PCSB however decided to drill DD-1 due to its large four way dip closure (approximately 250 km2), volume in-place and potential to open up other deep plays.
DD-1 is PETRONAS' first Ultra High Pressure High Temperature (HPHT) well, located in southern Malay Basin to evaluate gas in Group M (Early Oligocene age). It penetrated Group M in D Field and reached its final TD at 4350 m TVDSS. It recorded temperature and pressure of 488oF and 13900 psi respectively. DD-1 proved that the petroleum system is working for the deep play by intersecting several gas bearing sandstone units namely M20, M30, M60 and M70 (C1-nC5, total gas 5% to 13%). Reservoir effectiveness is the major issue - low porosities (3% to 8%) and extremely low permeability (0.0025mD). Well testing over M20 flowed gas to surface and was flared, however the testing was deemed inconclusive. The HPHT nature of the well also presented operational challenges such as drilling within narrow mud weight and fracture gradient margin and the availability of suitable HPHT logging tools.
Well results indicated that Group M was gas bearing; however at this stage is not commercially recoverable. The deep play potential remains to be commercially exploited but better understanding of natural fracture networks and the utilising of advanced technology will be required.

1.0 Introduction
DD-1 well is located approximately 236 kilometers northeast of Kemaman Supply Base (KSB), in water depth of 75 meters offshore Peninsular Malaysia (Figure 1). The prospect basically lies below the existing D Field which is currently being produced from the shallower Group I, J, K and L reservoirs.
The primary objective of the proposed DD-1 is to evaluate the hydrocarbon potential of the Group M sandstones which are within a structural four-way dip closure, the first ever well to test Group M in D Field. DD-1 is PETRONAS' first Ultra High Pressure High Temperature (HPHT) well; it was spudded on 01 March 2013 and after five months of drilling campaign, it successfully reached final TD at 4388 m MDDF on 18 July 2013. It experienced high temperature and high pressure of 488oF and 13900 psi at final TD.
Successful Application of Customized Fluid Using Specialized Synthetic Polymer in High Pressured Wells to Mitigate Differential Stikcing Problems by Minimizing Pore Pressure Transmission
Authors: Al-Muhailan Mohannad Sulaiman , Rajagopalan Arun , Al-Shayji Al Aziz Khalid , Jadhav Prakash Balkrishna , Khatib Faiz Ismail 
Published: May 2016

Abstract
Drilling deep wells in Kuwait has become a challenge due to excessive overbalance pressures up to 3,500 psi applied across a highly permeable sandstone/shale formation. High differential pressures leading to tight hole, string stalling, differentially stuck pipe and induced losses contribute to considerable non-productive time. The existence of a high pressure salt zone below this interval and a seven casing string design removed the further option of zonal isolation by casing. Traditionally, oil based mud with Calcium Carbonate of different sizes was used to reduce fluid invasion, but with limited success.
A customized fluid system was designed to overcome the issue of high overbalance pressure targeting improved bridging, minimized pore pressure transmission and wellbore strengthening with increased hoop stress. Software modelling and permeability plugging tests were performed to evaluate the fluid behavior under downhole conditions and to predict the characteristics of induced micro fractures based on rock mechanics. Porosity, permeability and induced micro fractures were considered to optimize the bridging mechanism. These results identified a synthetic deformable sealing polymer combined with sized graphite and ground marble showed considerable improvement in minimizing filtrate spurt loss without altering the rheological parameters and stability of the OBM.
A inclined well in sandstone/shale formation was selected for the application after suffering multiple wellbore instability and differential sticking incidents, resulting in more than 800 hours of non-productive time and a sidetrack. The new inclined section was successfully drilled with a stable wellbore, smooth trips, and no tight hole or sticking incidents. The borehole remained completely stable, even after 16 hours of 13 5/8" casing string suspended in 16" open hole without circulation.
This paper analyzes the historical problems encountered in this sandstone/shale formation, and presents the solutions developed based on these problems and case histories of the successful field application of this customized fluid.
Offshore Sub-Basalt Exploration Using CSEM and MT
Authors: Panzner Martin , Kumar Krishna , Mrope Frida 
Published: May 2016

Abstract
Seismic sub-basalt imaging is challenging and often leaves remaining uncertainties about the sub-basalt structures. This paper considers how the marine controlled source electromagnetic (CSEM) and the magnetotelluric (MT) method can reduce the interpretation uncertainty by providing structural and quantitative resistivity information about the thickness and extent of the basalt sequence and the sediments below. In order to demonstrate the capability of these technologies, we will present two recent studies: (1) a synthetic inversion test from a realistic model based on well-log and seismic data and (2) inversion of field data acquired over the Faroe-Shetland Escarpment. We will show that this information can also be used to improve the velocity models for seismic depth imaging.

Introduction
Basalts are extrusive igneous rocks that can be found worldwide. Often the compact basalts are interlaid with volcanoclastics and sediments. Such sequences are formed by a series of eruptive events. Sub- and intra-basalt sediments can be hydrocarbon bearing, which makes sub-basalt exploration very interesting to the oil and gas industry.
Using seismic, one can usually establish the top of the basalt accurately. But due to the heterogeneities in the basalt layer in combination with high seismic impedance contrasts it can be challenging to accurately image the base of the basalt and underlying sediments (Fliedner and White, 2001; Fruehn et al., 2001). Conversely, several modelling and inversion studies have shown that EM methods can play a significant role in mapping both the thickness of the basalt layer and the sediments below (Jegen et al, 2002; MacGregor, 2003; Hoversten et al.,2013; Heincke et al., 2014).
The CSEM and MT methods utilize electromagnetic (EM) fields to measure resistivity variations in the sub-surface. Compact crystalline rocks such as basalt have virtually no porosity and are very resistive in contrast to sediments with comparably large pore spaces filled with more conductive pore fluids. That makes EM methods well suited for imaging of the thickness of the basalt layer and the structures underneath. In this paper, we discuss two studies, (1) a synthetic data study based on a realistic model (Herredsvela et al., 2012) and (2) a field data example from the Faroe-Shetland Basin.

Synthetic Basalt Model
Figure 1 shows the model which was used for the synthetic modelling and inversion study. The water depth in the model varies from 300 to 350 m. The model consists of a fine layered basalt sequence with a varying thickness from 200 meters to almost 2 kilometers and a detailed sediment structure underneath the basalt. The internal structure of the basalt sequence is based on the observations from well logs and seismic. It consists of many thin layers with varying resistivities which are sensed as one thick anisotropic layer due to low resolution of the EM methods. The information used to construct this model makes it analogue to a realistic scenario.
Early Meteoric Diagenesis and Porosity Preservation: Stratigraphic Traps in Carbonate Grainstones
Authors: Major R P 
Published: May 2016

Abstract
It is well established that aragonite sediment can be rapidly cemented in near-surface diagenetic environments when exposed to meteoric (fresh) water. Indeed, there are published examples of calcite cementation of aragonite sediments that resulted in rocks hard enough to require a hammer for sampling, and some of these examples formed in time periods shorter than a human lifetime. Complete mineralogic stabilization requires longer time periods, although within meteoric phreatic lenses in humid environments alteration to 100 percent low-magnesium calcite can occur as quickly as 5,000 years.
Early lithification, especially lithification and complete mineralogic stabilization in paleophreatic lenses, has been demonstrated to produce zones within carbonate rocks that are more resistant to compaction and porosity destruction during burial than superjacent and subjacent rocks. Thus, early exposure to meteoric phreatic diagenesis is one mechanism for producing stratigraphic traps; that is, hydrocarbon reservoirs in which the trapping mechanism is not controlled by structural deformation.

Introduction
Ehrenberg et al. (2012) reviewed numerous published examples of porosity in carbonate rocks interpreted to have formed by late-stage burial dissolution and concluded that most of these interpretations were based on equivocal data. Although Ehrenberg et al. are perhaps too quick to dismiss some very well documented examples of this phenomenon, their principal conclusion seems at least consistent with what is known about the burial diagenetic environment. That is, in contrast with near-surface diagenetic environments in which several mechanisms can move a great many fluid pore volumes through a sediment in geologically short periods of time, fluids in burial diagenetic environments move sluggishly and generally do not have an obvious exit pathway. Thus leaching in burial diagenetic environments, although clearly important in some hydrocarbon reservoirs, is probably neither common nor volumetrically significant in the stratigraphic record.
It has been well documented that the general fate of porosity in carbonate sediments and rocks is progressive destruction during burial (for example, Schmoker and Halley, 1982). Thus, porous and permeable rocks at depth, i.e. reservoirs, are the anomalies rather than the generalization.
If one accepts these two generalities: late-stage leaching is rare and porosity is normally destroyed during burial, then it follows that porosity preservation during burial is at least one important factor in the formation of hydrocarbon reservoirs. This paper reviews one mechanism for preserving porosity during burial that may be quite common.
Foams Prove Effectiveness for Gas Injection Conformance and Sweep Efficiency Improvement in a Low porosity Fractured Reservoir – Field Pilots
Authors: Ocampo-Florez Alonso , Restrepo Alejandro , Rendon Natalia , Coronado Jorge , Correa Juan Alejandro , Ramirez Diego Alejandro , Torres Monica , Sanabria Rosa , Lopera Sergio Hernando 
Published: May 2016

Abstract
Foams have proved to be efficient to block temporarily high conductivity layers, and improving gas injection conformance and sweep efficiency in predominantly matrix reservoir systems, at least at lab and field pilot tests; nevertheless, its successful use in naturally fractured reservoirs has not been fully demonstrated as of today. This paper presents the evaluation process and the successful results for two (2) foam EOR field pilots performed in the Cupiagua in Recetor field; a gas condensate system whose main reservoir is a low porosity (&lt;6%) quartzarenite with matrix permeabilities in the range of 0.01 to 10 mD, and where the fracture corridors are confirmed to play an important role both in well productivity/injectivity, and in the inter-well connectivity and gas channelling between gas injectors and oil producers.
The reservoir has been developed under massive hydrocarbon gas re-injection, and the current recovery factors of condensate are between 35–40%. The foam treatments were deployed in two gas injectors located in different areas of the field, each one impacting two oil producers, and exhibiting different levels of gas recycling, with GOR ranging between 40,000 and 100,000 scf/STB.
Both operations were performed via bull-heading using the SAG method. The results for both jobs showed a temporary reduction in gas injectivity, with slow recovery to its base line within the next 3 months. Despite showing little changes in the injection profile at the gas injectors, the two producers affected by the first job showed a clear change in GOR trends, and a consistent ramp-up in oil production rates during a period of at least 7 months, reaching a maximum increase between 15 and 30 % over their base line productions. The second job was performed to confirm consistency and repeatability of technology, and evaluate duration cycle of blocking and benefit effects. Early surveillance indicates positive response both at the gas injector, and the oil producers. Results herein presented, confirm the viability for foams as an EOR method for this naturally fractured field, and open EOR opportunities for other fractured reservoirs located in the same basin and exploited under gas injection schemes.
THE INTEGRATION OF PETROLEUM SYSTEMS ELEMENTS FOR HYDROCARBON PROSPECTING IN PRE-MESSINIAN STRATIGRAPHIC SECTION OF THE OFFSHORE WEST NILE DELTA, EGYPT
Authors: Keong Ong Swee , Bt. Abdullah Azirul Liana , Bin Ahmad Fuad Ahmad Syahir , Bt Hamdan Norazean , Bt Anuar Azlina , Basu Debnath , Ysaccis Raul , Murthy K S , Kim Taesoo 
Published: May 2016

Abstract
The study area is situated in the offshore West Nile Delta basin towards the northeast of Alexandria, Egypt. This is a major petroleum habitat hosting many gas and condensate fields. The present paper summarizes the petroleum system elements for hydrocarbon prospecting in the Messinian and deeper stratigraphic section based on an integrated study of seismic and well data.
Mixed well results have been observed in the area with proven gas fields found in stratigraphic fluvial channels in the Messinian. Rotated fault blocks and fault dependent traps were tested but no discoveries were proven. Failure could be due to trap integrity issues and inadequate migration pathways. Potential remaining stratigraphic plays identified are deepwater slope channels in the pre-Messinian to Oligocene section similar to overlying Pliocene gas fields.
Depositional models based on seismic attribute mapping and a few wells generally depicts a NW-SE facies belt trend dominated by deepwater slope channel complexes flanked by slope shales ranging in age from Upper Oligocene to Miocene (Pre-Messinian). In the Messinian, the depositional environment is associated with a major sea-level drop with consequent exposure of the shelf/slope. It contains predominantly incised valleys and fluvial-fills flanked by interfluves.
The hydrocarbon charge is expected from Cretaceous-Jurassic and Early Tertiary pro-delta shale source rocks (Marten et al., 2004). Evidence of highly mature thermogenic gases (2.0 % - 2.5% VRo) advocates the assumption of the presence of a deeper source rock contribution from limited well calibration. Basin modeling results shows that the modelled source rocks are presently in the hydrocarbon generation window. Source rock generation has occurred very late from 9.0Ma to 1.0Ma and migration timing post-dates trap formation. Traps are expected to be charged vertically and through fault conduits as observed in well results.
This study paved the way for a better understanding of the petroleum system elements which consequently forms the basis in risking the Messinian and deeper exploration plays and shows that the Messinian stratigraphic channel plays are most prospective.
Automated Racking-Board Pipe-Handling System Eliminates Hazards of Tripping Operations, Reduces Rig Personnel, and Creates Consistent Tripping Speeds in Line with Best Rig Crew Performance
Authors: Jaber Adham Sultan 
Published: May 2016

Abstract
Tripping of drill pipe is known to be one of the most dangerous and physically demanding jobs on the rig and involves a derrickman and rig floor hands that are often subject to various injuries. Now this hazardous operation can be automated, which moves personnel out of harm's way and simultaneously creates attractive and very consistent tripping results.
In this paper we will discuss field experiences while introducing such a system into an active onshore drilling operation in Canada. The unit is lightweight and fit for first installations, or it can serve as a retrofit-capable package. The Iron Derrickman S3 comes with a custom racking board that pins directly in the place of a conventional racking board. Complete with a standalone control system and power unit, it makes for a quick and easy addition to any rig. It immediately increases safety by actually removing the Derrickman from his exposed position and simultaneously making a floor hand redundant. The reduced incident exposure realized from removing the need for a Derrickman to climb up the mast and manhandle a nearly 9000lb stand of pipe with the supporting floor hands on the rig floor that control the bottom of the stand (in the red zone) and drive it around the floor each time a stand of pipe is needed, is tremendous. As you can see in the IADC Industry LTI's numbers from 2013, the incidents on the floor, in the racking board and involving Derrickman make up the lion's share of all LTI's on the rig annually. The Iron Derrickman S3 is an engineered solution that will help eliminate these hazards.