bluuebunny/crossref_metadata_2025_split huggingface dataset:
Maqāmāt Dalam Manthiq Al-Thayr Al-Attār
Authors: Ni`am Syamsun 
Published: February 2016

<p><strong>Abstract</strong> : Attār is one to be accounted amongst the greatest sufi poets of Persia sufis in the history of Sufism who has notable contibution to the esoteric Islam (Sufism). He packed his mystical teachings in the form of poetry and verse, -to be more interactive and expressive- though his teachings are not different with his predecessors, particularly of those who inspired by the principle of mystical union; and Attār is among the Sufis who have managed to reach the highest peak in the mystical journey. According to Attār , there are seven valleys that must be passed by spiritual traveler (<em>sālik</em>) in his mystical journey, as mentioned in <em>Manthiq al-Thayr</em>. In this work he use the language of poetry to reveal the process of a servant to God through the stages (<em>maqāmāt</em>), and Attār gives the parable <em>maqāmāt </em>is like a bird -burung flying looking for the king. Attār call <em>maqāmāt </em>is the term valleys, of which there are seven valleys.</p><p><strong>Ke</strong><strong>ywords : </strong><em>Maqāmāt, seven valleys, fanā’, </em><em>divine love</em></p><p><em><br /></em></p><p><strong>Abstrak</strong> : Attar adalah salah satu sufi besar Persia yang pernah dikenal dalam sejarah tasawuf. Attār telah banyak memberikan kontribusi pemikirannya dalam khasanah keilmuan Islam esoteris (tasawuf). Ia mengemas ajaran tasawufnya dalam bentuk puisi dan syair, —sehingga tampak lebih menarik— meskipun ajaran-ajaran yang disampaikan kurang lebih sama dengan para sufi pendahulunya, terutama yang menganut paham <em>mystical union</em>; dan Attār adalah di antara sufi yang telah berhasil mencapai puncak tertinggi dalam perjalanan mistisnya itu. Menurut Attār, ada tujuh lembah yang harus dilalui <em>sālik </em>dalam menempuh perjalanan mistisnya, sebagaimana disebutkan dalam <em>Manthiq al-Thayr</em>. Dalam karyanya ini, Attār menggunakan bahasa puisi dan syair untuk mengungkap proses seorang hamba menuju Tuhan melalui tahapan-tahapan (<em>Maqāmāt</em>), dan Attār memberikan perumpamaan <em>maqāmāt </em>tersebut seperti burung-burung yang terbang mencari rajanya. Attār menyebut <em>maqāmāt </em>tersebut dengan istilah lembah-lembah, yang jumlahnya ada tujuh lembah</p><div class="WordSection1"><p><strong>K</strong><strong>ata-kata Kunci: </strong><em>Maqāmāt, </em><em>tujuh lembah, fanā’, cinta ilahi<br /></em></p></div>
Managed Pressure Drilling as Well Control in Deepwater GOM: Challenges to Current Modes of Thinking
Authors: Weems Matt , Moore Dennis , Leach Colin 
Published: February 2016

Abstract
Managed Pressure Drilling (MPD) has gained industry acceptance with surface BOP stacks where improved control of downhole pressure has been achieved. The industry is currently beginning to see implementation of MPD systems in deepwater environments where narrower drilling margins make improved pressure control even more important. Despite the evident need for such applications the industry has been slow to fully utilize MPD techniques in deepwater. The question this paper seeks to address is, "What is preventing us from employing the same MPD systems currently being used with surface stacks in a deepwater environment?" This question encourages challenging conventional modes of thinking in the industry concerning risks pertaining to risers and well control when utilizing MPD systems. This paper draws on some of the difficulties, thinking, and achievements when such a system was implemented for drilling a deepwater GOM well. MPD in deepwater involves new equipment, capabilities, and risks. Full utilization of MPD systems in a deepwater environment requires re-thinking several things including primary well control and the conditions to which the riser is exposed.
MPD Dynamic Influx Control Mitigates Conventional Well Control Pitfalls
Authors: Bacon William , Sugden Catherine , Brand Patrick , Gabaldon Oscar , Culen Martin 
Published: February 2016

Abstract
Managed Pressure Drilling (MPD) dynamic influx control techniques offer substantial advantages over conventional well control, including reduced influx size, and the ability to control and circulate an allowable influx without requiring conventional methods. With careful planning and execution, MPD dynamic influx control can yield considerable increases in safety and efficiency.
Many issues with conventional well control, particularly in deepwater operations, can be mitigated or even eliminated using dynamic influx control. Notably, conventional methods passively rely on the influx to increase wellbore pressure sufficiently to balance reservoir pressure, resulting in needlessly large influx volumes. In contrast, MPD methods quickly detect and actively apply pressure to control an influx in a fraction of the volume.
Furthermore, conventional influx removal methods are typically slow, leading to drawn out well control events with high likelihood of further complication, such as stuck pipe and secondary influxes. Conversely, using dynamic influx control, an allowable influx may be controlled and removed from the wellbore in a few hours, not days.
In this work, methods that address concerns with current well control practices through application of dynamic influx control are outlined. In addition, transient, multiphase simulation is used to demonstrate comparison between dynamic influx control and conventional well control, clearly quantifying potential benefits of adopting these new methods.
Evolution of the MPD Operations Matrix: The Influx Management Envelope
Authors: Culen M. S. , Brand P. R. , Bacon W. , Gabaldon O. R. 
Published: February 2016

Abstract
The MPD Operations Matrix was introduced in 2007 to serve as an operational guide for drilling MPD sections. The intent of the matrix is to balance operational, well, and equipment limitations with ‘acceptable’ influx volumes. The operations matrix has become the cornerstone of MPD projects worldwide, and is in fact a mandatory component of planned MPD wells in the Gulf of Mexico. In its current format, guideline for use of the matrix include developing criteria to categorize an influx such as its state, rate, duration, and size. Calculating these criteria and populating the matrix with them all can lead to some confusion, and many default to including only an influx size for simplicity, despite the fact that the other criteria can help in characterizing an influx further. Further, the acceptable influx size is most often limited to the detection capability of the MPD equipment, and not what the overall primary barrier envelope can handle.
In this paper, a method for calculating acceptable influx volumes is outlined, and the calculation algorithm is adapted to a software tool. The results are displayed graphically in an Influx Management Envelope. The Influx Management Envelope is an evolution of the tabular MPD Operations Matrix, and includes all of the same influx indicator and pressure criteria, but offers a simpler, straightforward operational interpretation of influx limits.
The effects of section depth, well geometry and hole size on influx volume limits will also be investigated, and development of a sample Influx Management Envelope is presented.
Loss of Circulation an Indication of Hydrocarbon Influx?
Authors: Vavik D. , Sangesland S. , Shayegh M. 
Published: February 2016

Abstract
Managed pressure drilling (MPD) techniques such as; constant bottomhole pressure (CBHP) and pressurized mud cap drilling (PMCD) have made it possible to drill challenging prospects that with conventional techniques are considered undrillable. Drilling in naturally fractured carbonates, highly permeable unconsolidated sands and/or cavernous/vugular formation, often leads to loss of circulation. The mud losses in these kinds of formations are however not normally caused by hydraulically induced fracturing due to excessive pressure. When these extreme loss zones are intersected, the more heavy drilling mud will fall to the bottom and exchange or swop places with the less dense formation fluids.
In some areas like the Gulf of Mexico, deep water outside Brazil and in the arctic climate of the Barents Sea in northern Norway, we can see these kinds of challenging formations in combination with deep and cold seawater. The drilling riser will act as a giant heat exchanger that will cool down the mud that is circulated. The objectives and scope of this paper have been to see what happens to the total active volume if relative cold mud swops place and starts to mix with a relative warm hydrocarbon gas deep down in the loss zone and/or in the wellbore annulus.
PVT simulations and a study found that a net volume reduction will take place when the fluids are mixed, due to higher compressibility and lower specific heat capacity of the relative warm hydrocarbon gas compared to the mud. Equally important, the study also showed that there can be a risk of gas hydrates forming. If hydrates form it will result in an additional reduction of the volume. These volume reductions can be observed as loss of circulation or abnormal reduction in the active pit volume. Hydrocarbon gas influx caused by gravity-induced swop-out will be partly or completely concealed by the volume reduction taking place at the same time. Kick detection based on volume control (flow-in vs. flow-out) may therefore not work when drilling in naturally fractured or highly permeable formations, where influx caused by gravity-induced swop-out takes place.
Drilling Through Layers of Unstable Shale Formations and Depleted Sand Sequences, the Managed Pressure Drilling/Wellbore Strengthening Approach to Successfully Drill Offshore Development Wells: A Case History
Authors: Henry I. , Hernandez J. , Craig H. , Ngan A. , Arnone M. , Boutalbi S. , Harvey M. 
Published: February 2016

Abstract
Two hole sections (12-1/4″ x 14-3/4″ and 10-5/8″ x 12-1/4″) were planned to be drilled through sequences of unstable shale and depleted sand packages with no drilling windows, which are defined by the shale Wellbore Stability Gradient (WBSG) delimited by the "intact wellbore wall zero failure degree" and the depleted sand fracture gradient criteria. Historically, significant non-productive time (NPT) associated with wellbore instability and lost circulation had resulted in sidetracks and other costly remediation in both hole sections. The operator and the service provider have identified the Constant Bottomhole Pressure (CBHP) variant of Managed Pressure Drilling (MPD) and wellbore strengthening as the necessary technology approach to safely drill through both challenging hole sections. Dynamic and static wellbore strengthening were applied to increase the near wellbore stresses across the depleted sands to create a drilling window, whilst the MPD CBHP was used to mitigate bottom hole pressure fluctuations and cyclic stress across the shale packages.
The MPD well evaluated in this paper had just four hours of non-productive time related with downhole problems and wellbore stability, a minimal fraction when compared to the 980 hours lost in the previous conventional offset well. The MPD well did not require any back reaming operation, whereas the offset well in the area required 7 back-reaming events to get a good quality wellbore. A total of 533 hours were required to drill the 2 hole sections in MPD compared to the 2,410 hours required to drill the same sections conventionally in a previous offset well in the area.
This paper summarizes the key MPD planning, engineering, results obtained and lessons learned that delivered a successful campaign of producer wells.
Innovative Techniques for Unconventional Reservoirs: Managed Pressure Cementing Application in Western Argentina Shale Formations
Authors: Ficetti S. , Baggini Almagro S. P. , Aldana S. , Arismendi H. A. 
Published: February 2016

Abstract
The focus of the international oilfield industry is clearly increasing toward the development of unconventional plays worldwide, and this increased focus is evident in the development of local shale formations in the Neuquén basin. The emerging unconventional market in western Argentina constitutes most of the drilling operations in the region.
Well integrity is a key requirement for these projects that demand distinctive completions through massive hydraulic fracturing. Existing conditions within the field add major challenges to the overall well construction process, considering the high pore pressure and the ultranarrow operative window (i.e., tight pore-fracture margin) present along the production section. These conditions increase the demand for dynamic pressure management techniques.
Shale-targeted wells were cemented overbalanced at first; however, the failure rate was high, leading to annular pressure buildup (APB) problems requiring costly remediation. Some wells could not even reach total depth (TD) and were temporarily abandoned. Presently, most of the unconventional wells drilled in the area are cemented using a managed pressure cementing (MPC) technique, which has considerably improved the success rate. After defining critical anchor points, an engineering design methodology is proposed to adjust a dynamic backpressure profile to effectively control the formers.
Considering the APB rate as the evaluation criteria in place, this engineering approach has made cement placement in local unconventional wells more effective than ever before, increasing the success rate from approximately 67% in 2013 to nearly 95% in Q1-2015.
An Improved Thixotropic Barrier Fluid Used to Prevent the Commingling of Fluids While Tripping on Managed Pressure Drilling (MPD) Wells
Authors: Ramirez-Angulo Jessica Paola , Shumway William Water 
Published: February 2016

Abstract
The drilling fluid used for managed pressure drilling (MPD) operations is of a lower density than that required for normal overbalanced drilling. This means that the hydrostatic pressure from the drilling fluid is often lower than the formation pore pressure. Because of this, the drilling fluid is "at balance" or even "underbalanced" when static. A hydrostatic overbalance is required when tripping to avoid the influx of formation fluids, which may result in a kick. One common way the hydrostatic overbalance is accomplished is by using the mud cap method, where a high-density fluid is placed on top of the underbalanced drilling fluid, resulting in the desired total bottomhole hydrostatic pressure. The major shortcoming of the mud cap design is the risk of comingling of the mud cap with the lower-density drilling fluid beneath it.
An attempt to viscosify the high-density drilling fluid had been made to effectively address this shortcoming; however, several issues were encountered, including more difficult movement and storage of the tripping fluid, along with the risk of increasing the well's bottomhole pressure while pumping the large, viscous pill into place. A better solution to the comingling issue is to place a physical barrier between the two fluids to prevent their mixing. Although barrier pills have been used in the past, they were either limited by not being viscous enough to effectively separate the mud cap from the lower-density drilling fluid or failed as a result of routine drillsite contamination.
An improved barrier pill was developed to offer superior performance in fluid separation as well as to simplify tripping in MPD operations. The new pill involves novel synthetic materials, rheology engineering, and extensive testing. This fluid exhibits a very high degree of thixotropy, far beyond conventional clay or polymer suspensions. When the barrier is static, the progressive gel develops exceptional strength capable of resisting pressure and buoyancy forces. The shear-thinning behavior ensures that agitation and flow make the mixture mobile and pumpable. Shear-thinning properties permit placement of the pill as well as the passage of pipe, coiled tubing, and wireline through the resultant gel without hindrance. With a relatively short coverage interval, the gel can be broken without generating high ECD values. The improved barrier pill will maintain separation and prevent comingling of muds with different densities. Lab testing has shown that the pill works with a variety of fluid system, resists contamination, and is able to maintain integrity with a density differential greater than 6 lb/gal.
The developments of this improved barrier fluid are the subjects of this paper.
Production Optimization of Foam Assisted Lift (FAL) Wells and Evaluation of Good and Bad Practices to Ensure Maximum Production
Authors: Uddin M. Farooq , Tayyab Imran , Koondhar Nadeem H. , Ahmed Qazi Ismail , Soomro Aijaz Ali 
Published: February 2016

Abstract
Throughout the production life of a gas well its reservoir pressure declines and well becomes prone to liquid loading. The stationary liquid column in the wellbore exerts back pressure on the formation resulting in decrease or sometimes ceases the production. The overall outcome of this phenomenon is reduced recovery factor resulting in loss of reserves.
Increasing Liquid Gas Ratio (LGR), decreasing gas rates and velocities with decreasing reservoir pressure are the main factors contributing in liquid loading. Various methods have been used in the industry to de-liquefy gas wells and maintain production rates. One method to de-liq a gas well is down hole soap injection through 1/4" or 3/8" capillary string to reduce the effective density and surface tension of the produced liquids. This method is cheap and effective, no external source of energy is needed since it utilizes reservoir energy. Injected soap or foam must be selected according to the reservoir characteristics.
This paper shares the case studies of different wells having depleted reservoir pressures and liquid loading tendency. Foam Assisted Lift (FAL) was implemented on these wells as a de-liq technique, detailed study was carried out to observe their production behaviors and economic benefits from FAL. This work also incorporates the good and bad practices to ensure FAL is effectively de-liquefying a gas well to maximize production.
The different practices proposed in this study can be used as an analogy to ascertain soap injection is performing in the best way to attain incremental production from depleted gas wells with liquid loading problems.
Study of Asphaltene Precipitation during CO2 Injection in Light Oil Reservoirs
Authors: Ali Muhammad , Dahraj Naeem Ul. , Haider Syed Afraz 
Published: February 2016

Abstract
CO2 injection is considered as one of the successful methods used for enhanced oil recovery (EOR) in oil fields to recover residual oil. It increases mobility and reduces viscosity and interfacial tension. Asphaltene precipitation and deposition phenomena appear in petroleum reservoirs due to change in temperature, pressure, and liquid phase compositions; either during the primary production or enhanced oil recovery processes. Asphaltene precipitation might occur due to CO2 injection in light oil (&gt;30° API) reservoirs which may cause blockage of production system, decrease in permeability, wellbore plugging and change in porosity. Experimental data concludes high asphaltenes precipitation and lower asphaltene solubility in light oils. Hence severe damage to formation can happed sue to asphaltene precipitation, in some cases the loss might be irreversible. This paper furnishes the investigation of asphaltene precipitation caused by CO2 injection. In this regards interaction between asphaltene and formation, precipitation quantity under different injection flow rates of CO2 at the constant injection pressure have been investigated. Results conclude that there is direct proportionality between asphaltene precipitation and amount of injected gas in the core sample, whereas inverse proportionality between asphaltene precipitation and increased injection flow rate of the gas at constant injection pressure.
Method to Optimally Produce Wells Having Salt Precipitation Issues
Authors: Soomro Aijaz Ali , Hadi Abdul , Awase Azar , Koondhar Nadeem Hussain , Ahmed Noor 
Published: February 2016

Abstract
A common problem that occurs in low producing gas wells is the salt precipitation in the near wellbore region or within the wellbore. These salts are generally formed by the changes in pressure but mainly temperature affect the solubility. Salts formation cause additional pressure drop resulting in production impairment and may even result in abandonment of wells. Salt problems occur over a very limited range of producing conditions and are generally seen in mature, depleted gas fields. This paper presents a proactive approach to prevent salt scaling in low pressure gas wells in United Energy Pakistan Limited concession areas.
Early prediction of salt precipitation is vital to optimally produce the well; this depends on individual wellbore pressure & temperature profiles and production chemistry. The paper discusses the diagnostic approach using produced water chemistry, WGR history and Nodal Analysis to predict the optimum bottom-hole pressure to avoid salt precipitation from produced water.
A number of wells in our concession area had severe salt build-up issue and sharp decline in production was observed. Different methods like wellbore cleanout using coiled tubing, mechanical slickline tools and re-perforations to remove salt plugging were implemented but they proved to be short lived resulting high cost, increased intervention frequency and uneconomical gas production from the wells.
In order to mitigate the salt build-up issues, the wells were produced at the optimum bottomhole pressures simulated through nodal analysis, for the given well conditions & produced fluid chemistry, to avoid salt precipitation in the wellbore. The implementation resulted in decelerated salt precipitation from produced water resulting stabilized production, reduced well interventions frequency and improved production economics.
Pressure Transient Testing and Fluid Profiling using Wireline Formation Tester Helps Optimizing Completion Strategies: Pakistan Tal Block Case Study
Authors: Abbas Asad , Kakar Abdul Malik , Farooq Umar , Ahmed Jawad , Samir Magdy , Mughal Haroon , Bari Abdul , Khalid Arsalan , Zubair Talha , Dar Usman 
Published: February 2016

ABSTRACT
Well testing is very challenging especially in northern parts of Pakistan, as there are complex lithologies and multiple formations encountered in a single well. These formations include both fractured carbonates and sandstones. In addition, lower matrix porosities make it more difficult and time consuming as it can take several weeks to months to test multiple formations individually using a casedhole drillstem test (DST). These tests impact the overall well cost due to the extended rig time required and production loss. Extended buildups are a huge concern that must be kept in consideration due to the high rig-time requirement.
This paper describes the application of a wireline formation tester (WFT) for interval pressure transient testing (IPTT), which is also referred to as a mini-DST, to estimate flow regimes and reservoir properties along with vertical pressure profiling, fluid identification, and sampling. This technique was applied at two of the exploratory wells in TAL block. There, WFT was deployed with a single probe and straddle packers to achieve the desired results across four potential reservoirs. Vertical pressure profiles across the prospective formations were acquired using the single probe; this was followed by a mini-DST using straddle packers to test zone by zone for fluid type, collect samples, and record pressure buildups. Real-time pressure derivatives were monitored to optimize the buildup time at each station depth. This integrated IPTT gave necessary reservoir information in a very short span of time. It saved significant amount of time and costs, especially rig costs and entire well testing cost giving valuable information for completion strategy.