bluuebunny/crossref_metadata_2025_split huggingface dataset:
Eliminating Perforating-Related Formation Damage in Gravel-Pack Applications Utilizing New One-Trip-Sand Control Completion Technology
Authors: Garfield G. 
Published: March 2015

Abstract
Formation damage caused by perforating is among the highest risks in well completion. This paper examines a new technology for completing wells in unconsolidated formations that installs a liner hanger and sand control mechanism in a single trip to eliminate explosive perforation charges and associated formation damage risk. In addition to eliminating perforating, the technology reduces the cost of well construction by allowing the production liner, flow conduit, primary cementing, and sand control tools to be run in a single trip.
The perfless completion system uses telescoping tubes that extend from the liner into the formation by applying hydraulic pressure and mechanical force. Once the tubes are extended (or telescoped), the liner is cemented in place. The tubes, which contain sand control media, form conduits from the formation to the casing ID. No large, high-horsepower fluid pumping treatments are required. Neither are after-completion drilling mud and fluid-loss control measures, both of which can cause formation damage. The new completion method eliminates gravel packing and minimizes intervention in completion operations, saving substantial rig time. It also simplifies operation logistics, especially in remote or offshore environments.
This new technology was developed by a Joint Investment Project (JIP) that included three major operators, a large service provider and a small technology company. This paper describes initial field test results of the new system, cost comparisons with existing methods, and expected economic benefits over the lifetime of wells in typical applications of this new technology.

Introduction
Reducing or eliminating formation damage caused by perforating can result in a more productive well over its lifetime. The history of formation damage caused by perforating has been well documented. Fractured and compacted zones, perforation gun debris, and broken formation blockages are common types of damage that can occur inside the perforation tunnel. Studies have shown that conventional perforating of cased wells can cause an increase in skin values, especially over the extended lifetime of the well. Studies have also shown that increasing the depth of penetration will increase not only the skin value of the well, but also the amount of fines in a perforation tunnel.
Probabilistic Reserve Estimation Constrained by Limited Production Data: An Integrated Approach
Authors: Minhas Haq Nawaz , Matteo Eugenio , Eikeland Kjersti Margrete , Mengoli Marina , Beswetherick Simon 
Published: March 2015

Abstract
Large uncertainties in structure and facies had been recognized in a major gas field in Pakistan after early production. The conventional reserve estimation methods had failed in providing a reliable estimate of gas-in-place (GIIP). It was possible to get a good history match of one-year production data using a wide range of GIIP through a slight and acceptable adjustment of porosity and permeability. The resulting possible range of GIIP could easily vary by a factor of 1.5. Structural uncertainties did not warrant volumetric estimates either. Material balance technique was questionable due to non-uniform drainage of the reservoir. Clearly these deterministic techniques of reserve estimation were not applicable at this stage of production considering the complexities of the reservoir. A probabilistic technique was therefore developed that addressed both static and dynamic uncertainties in an integrated approach while honoring the available production history. Combined treatment of static and dynamic uncertainties also ensured a better coverage of the entire sample space, thus making the probabilistic approach more reliable.
Latin Hypercube Sampling (LHS) helped minimizing the number of simulation runs while providing a reasonable coverage of the sample space. Yet we ended up with almost 1500 simulation runs. The process of history matching, ranking and keeping track of all these simulation runs demanded an innovative workflow. A number of software tools were used to automate and optimize this process. Out of 1500 simulation runs, the 200 best runs having minimum objective function through history matching were selected. These runs were later used for production forecasting, for providing a range of reserves, and for sensitivity analysis to identify the most influential variables. Structure and NTG were identified as the two most critical variables for *GIIP while residual gas saturation was identified as an additional sensitive variable for reserves. Different geostatistical realizations had little impact on GIIP or reserves.
Detecting and Modeling Cement Failure in High-Pressure/High-Temperature (HP/HT) Wells, Using Finite Element Method (FEM)
Authors: Shahri Mehdi , Schubert Jerome Jacob , Amani Mahmood 
Published: March 2015

Abstract
A successful cement job results in complete zonal isolation while saving time and money. To achieve these goals, various factors such as well security, casing centralization, effective mud removal, and gas migration must be considered in the design. For the cement job to be successful, the permeability of the set cement must be low enough to prevent any fluid flow through the cement, possibly damaging the casing. Therefore, the design of the cement must be such that it prevents:Micro-annuli formationStress crackingCorrosive fluid invasionFluid migrationAnnular gas pressure
In High Pressure/High Temperature (HPHT), cases, a more flexible cement which expands more than conventional cement may prevent cement failure.
The stress in the cement is strongly dependent on temperature and pressure as well as the lithology and in-situ stress. Since the stress is so dependent on temperature, the temperature variation must be precisely predicted to achieve the proper design of the cement slurry and eliminate excessive time spent waiting on cement. In addition, a post-job analysis is necessary to ascertain zonal complete isolation and avoid unnecessary remedial work.
By increasing the flexibility of the set cement (lowering the Young's modulus) we could reduced the tensile stress in the cement sheath during thermal expansion. This could be a solution to the problem of cement stability in high temperature cases.
Here we report the use of the Finite Element Method, (FEM), to investigate the stress fields around and inside the cement in and to forecast the condition of cement failure. This study mostly focuses on the cement-casing boundary. This method is more powerful than conventional stability methods since complex boundary conditions are involved as initial conditions and are investigated simultaneously to more accurately predict cement failure.

Introduction
There are many of challenges dealing with cementing wells under High Pressure High Temperature (HPHT) conditions. Cement design and placement are very critical under these conditions. Since the casing stability is very dependent on cement integrity, and bonding with the casing and formation, operators must do everything feasible in order to insure a successful cement job.
A Modified Purcell/Burdine Model for Estimating Absolute Permeability from Mercury-Injection Capillary Pressure Data
Authors: Huet Caroline Cecile , Rushing Jay Alan , Newsham Kent Edward , Blasingame Thomas Alwin 
Published: March 2015

Abstract
This paper presents the development and validation of a new semi-analytical, statistically-derived model for estimating absolute permeability from mercury-injection capillary pressure data. The foundations of our new model are the classic Purcell and Burdine equations which relate absolute permeability to capillary-pressure/wetting-phase-saturation properties. We also incorporate characteristic capillary pres-sure behavior using the Brooks-Corey power-law model.
The final form of our proposed model allows us to compute absolute permeability as a function of effective porosity, irreducible wetting phase saturation, displacement or threshold pressure, and basic pore size characteristics. We tested and correlated our model using 89 sets of mercury-injection (Hg-air) capillary pressure data – including core samples from both carbonate and sandstone lithologies. In summary, we found that our model consistently yields accurate results for a wide range of rock properties.

Introduction
The fundamental relationships between pore size/geometry and basic rock properties (e.g., effective porosity, absolute permeability, etc.) are well-documented in the petroleum and petrophysics literature. Moreover, the literature is replete with models for estimating or predicting permeability from basic rock properties. Nelson4 has developed a comprehensive re-view of the literature, and he has identified five major categories of permeability models based on the physical rock attributes used in the model development:The five major model categories specified by Nelson are:Petrophysical models,Models based on grain size and mineralogy,Models based on surface area and water saturation,Well log models, andModels based on basic rock pore dimensions.
In this paper, we focus on models that incorporate basic rock pore characteristics and dimensions, and specifically, pore characteristics as determined from capillary pressure data. Nelson has further classified these particular models as direct types since they not only relate rock permeability directly to the pore dimensions and connectivity, but also incorporate fundamental theories of fluid flow through porous media. Most of these direct methods – especially the early models developed in the 1940s and 1950s – use mercury-injection capillary pressure data to quantify the rock pore and pore throat characteristics.
Natural Gas Scenario - Pakistan Case Study
Authors: Zubairi N.A. , Qureshi N.A. , Haseeb A. 
Published: March 2015

Abstract
World Natural Gas scenario has changed rapidly in the last decade and Natural Gas is set to play an increasing role in meeting the future energy needs as demand rises across the world. Natural Gas demand has increased by 75% over the past twenty years and its share in the total energy consumption is globally expected to increase from 23% in 2002 to 28% by the end of 2005. Pakistan has proven reserves of 796.32 Bcm (28.10 Tcf) and net annual gas consumption of 34.09 Bcm (1.203 Tcf). At present Pakistan's energy mix comprises 50% of Natural Gas share and there is continuous rise in gas consumption with a target to extend it to about 55%. Paper discusses chronology of Pakistan's Natural Gas starting from first find in 1952 and development of most extensive transmission and distribution network over the years. Conclusively, the paper would focus to demonstrate the upcoming challenges in Pakistan to meet the growing demands in addition to the opportunities that such challenges bring along.

Introduction
Natural Gas has already played a vital role in shaping the industry outlook and meeting energy demands in North America, Western and Eastern European countries, and industrialized Asia due to its availability and environmental acceptance. The availability of Natural Gas worldwide and specifically the abundance in Middle East, coupled with its environmental acceptability and various applications across all sectors, will continue to play an increasingly important role in meeting demand for energy in the World. Natural Gas is one of the cleanest, safest, and most useful of all energy sources. Natural gas is the most precious energy source which has extremely efficient BTU input to BTU use ratio. It is also a major feedstock for the production of ammonia for use in fertilizer production and a cleaner fuel choice for power plants.

World Natural Gas Scenario
The World gas scenario has changed rapidly in the last decade. Today Natural Gas is the fastest growing primary energy source. Presently world Natural Gas proven reserves are 6,337 Tcf. More than 75% of world gas reserves are held by ten countries, which represent 40% of the total natural gas exports through pipeline and/or LNG. Pakistan is ranked at number 30 and represents 0.4% of world gas reserves.
Generation of Probabilistic Reserves Distributions From Material Balance Models Using an Experimental Design Methodology
Authors: Vahedi Arman , Gorgy Faryar , Scarr Kynan David , Sawiris Ramzy , Singh Updesh , Montgomery Paul , Clinch Simon , Sawiak Angela 
Published: March 2015

Overview of Malampaya Field:
The Malampaya-Camago Gas-Condensate field is a Tertiary Carbonate build-up that is situated offshore to the northwest of Palawan Island (Philippines) below 800–1200m of water. It was discovered by Occidental in 1989 (Camago-1) and is operated by Shell (45%) with Chevron (45%) and the Philippines National Oil Company (10%) as equity partners. The field has been supplying gas from five subsea production wells since late 2001 to three Gas to Power plants on Luzon Island. Available subsurface data include a 2001 high resolution 3D seismic survey, five production wells and six exploration/appraisal wells with wireline and borehole image data, including spot core in selected wells, pressure and well test data. A schematic of the Malampaya gas to power project is shown below.

Overview of Experimental Design (ED) Methodology
An extensive reservoir characterisation study was carried out by Chevron on a non-operated asset in 2004 to determine gas-in-place and reserves distributions. This paper outlines the Experimental Design (ED) methodology used in the study which using material balance models integrated the static and dynamic reservoir uncertainties with the excellent reservoir pressure history data that exists for the field.
The methodology incorporated a unique and "state-of-the-art" method for screening over 20,000 reservoir realisations to allow only those realisations that showed a close match to the pressure history to be included in the generation of GIIP and reserves distributions. This aspect of the ED methodology proved to be very powerful in generating reserves distributions in a "hands-off" approach without the requirement for traditional manual adjustment of reservoir parameters to get a "history match".
Integration of Microelectrical and Sonic Reflection Imaging Around the Borehole - Offshore UAE
Authors: Borland William H. , Holderson Jakob , Bu Al Rougha Hamad Ahmed , Sultan Akmal Awais , Chakravorty Sandeep , Al-Raisi Muatasim 
Published: March 2015

Abstract
Horizontal wells are commonly used worldwide to improve recovery of petroleum resources. Offshore Abu Dhabi, the carbonate reservoir contains sub-seismic features such as faulting and fractures that impact production and enhanced recovery. This paper is an attempt to identify and link fractures and faults observed near borehole with surface seismic in order to provide insight into their extent, distribution, characterization and implications on the reservoir production. The study resolved structural interpretation uncertainty in the 3D seismic, highlighted the variability in the injected water front advancement, and provided a methodology to link fine scale observation from micro-electrical image logs to intermediate sonic measurements and surface seismic.
Conventional sonic logging is similar to refraction seismic experiments carried out on the earth's surface except that, for the sonic, the source is higher frequency and the source receiver distance and receiver spacing is much closer. This allows the sonic to achieve a higher resolution velocity measurement over a shorter interval.
Sonic logging waveforms can also be processed for reflection information in a similar way to reflection surface seismic. Its higher frequency source thus allows for much higher resolution reflection information tens of feet away from the well.
The structural dip computations from pilot and horizontal image logs were linked with sonic reflections to mark probable fault locations and to construct a geological cross-section, which used to define the different reservoir layers that intersected along the well trajectory. Structural lineaments (faults and fracture zones) within a given reservoir layer were extended away from borehole by utilizing sonic waveforms. Due to small fault displacement (&lt;4 m) the fault was not originally picked on the surface seismic, but overlaying the interpretation on the attributes indicates the possibility of a fault. The results were subsequently validated by injection profile. Mapping these lineaments improved seismic interpretation, which ultimately lead to better well placement and validated existing dynamic data.
Reservoir Surveillance and Smart Fields
Authors: Potters Hans , Kapteijn Pieter Karel 
Published: March 2015

Abstract
One of the chief challenges facing the EP industry is to increase the recovery of hydrocarbons from the existing asset base. With access to new resources getting more difficult and production declines facing several major mature provinces, the awareness that we need to manage our assets differently is growing. Recovery optimization is therefore a growing issue with significant future capital, technological and workforce competence development implications.
One of the approaches to address the challenge is the "Smart Field" (a.k.a. "digital oil field") concept, introducing advanced system engineering and optimization concepts to asset management. This includes new IT-enabled ways of collaborative working and tight integration of surface and subsurface technologies. In this paper we will focus on novel approaches and technology for detecting and monitoring subsurface changes, an area often referred to as reservoir surveillance or reservoir monitoring. On the basis of examples we will argue that a paradigm shift in reservoir management is called for to ensure optimal field development..

Introduction
Traditional approaches to recovery optimization are too multi-faceted to do justice to in a few introductory remarks. However, there is ample evidence that if technological advances were adopted faster, hydrocarbon recovery for many types of fields would improve faster as well, and the value to investment ratio (VIR) for several types of new technology far exceeds unity. In the past decade, the increased role of IT to process, integrate and visualize data has provided many examples. Workflow process integration, encapsulation of knowledge in a shared earth model, advanced 3D visualization, increasing detail in reservoir models, and remotely controlled operation centers are increasingly adopted by most operators.
Another trend, which seems to be progressing at a slower pace, is the increasing awareness that the above IT-enabled advances, in spite of their undisputed value, are insufficient. For instance, more detailed reservoir simulation will certainly contribute to a better representation of available data, and industry thrusts to build more precise models, using tens of millions of grid blocks, should therefore pay off. However, the question whether available ("traditional") data is sufficient to turn precision into accuracy --an important distinction-- is asked less frequently than it should.
Integrated Strategies for Shipping and Terminal Development Associated With Qatar's LNG Development Strategy
Authors: Miller Douglas Scott , Richardson Andy 
Published: March 2015

Abstract
A key to bridging the growing distance between the gas supply and the end market is the development of the next generation of LNG tankers and the terminals needed to regasify the LNG.
As the distances increase, the shipping element of the overall project cost can have a significant impact on project economics. It has been estimated that the costs to acquire the necessary transportation could exceed the cost of the liquefaction plant. Increasing the size of these tankers from the traditional 135–140,000 m3 reduces both the initial investment (need fewer ships) as well as the unit operating costs. Qatar has led the way in working with classification societies, equipment vendors, technology licensors and builders to develop and qualify LNG Tankers with increased sizes ranging from 210,000 m3 (called QFlex) up to 265,000 m3 (called QMax) with an intermediate sized vessel approximately 243,000 m3 (called SFlex).
These vessels will also incorporate twin slow speed diesel engines and on-board re-liquefaction plants that will virtually eliminate cargo loss through LNG boil off. Qatar has developed an integrated fleet strategy that balances the economies of these next generation LNG Tankers with the flexibility desired for worldwide terminal access. Extensive and detailed port compatibility studies for these larger vessels have been conducted and continue to be revised.
To ensure liquid market access, RasGas' & Qatargas' shareholders have demonstrated a willingness to move downstream and invest both in existing as well as grass roots development in the terminals that will return the LNG to its gaseous state. This "New Era" for Qatar redefines the "Integrated Value Chain" model and completes the value chain from the Qatari wellhead to gas delivery into the consumer grid, all under the umbrella of Qatar Petroleum (QP), its partners and the LNG ventures RasGas and Qatargas.
Comparative evaluation of Carp testis as an alternative to 17 &alpha;-Methyltestosterone on Tilapia sex reversal
Authors: Khanal Nabin Babu , Shrestha M. K. , Rai Sunila , Bhujel R. C. 
Published: March 2015

17 α-Methyltestosterone (MT) is a commonly used synthetic androgen for the all male tilapia fry production. The probable residual effect of MT on human health and environment has been a concern. Two trials for two seasons were conducted to evaluate the effectiveness of carp testis (CT), as a source of natural androgen, on sex reversal of Nile tilapia (Oreochromis niloticus) and compare it with MT at Department of Aquaculture, Agriculture and Forestry University, Nepal,using completely randomised block deign (RCBD). Altogether 8 treatments with 4 for methyltestosterone (40 mg MT kg-1 of diet) and 4 for 75% rohu (Labeo rohita) testis. Both source of androgen were fed for 15, 18, 21 or 24 days. Treatments were replicated thrice. The result of methyltestosterone feeding for 24 days showed significantly (p<0.05) higher percentage of male (98.5±1.5) than 15 days (87.1±3.5) but was statistically similar with 18 (91.8±2.6) and 21(94.3±3.0) days feeding. Similarly percentage of male obtained with18 (84.8 ±2.1) and 21 (85.8 ±2.9) days of CT feeding were statistically similar (p>0.05) with 24 days and also with 15 days CT treatment but the result of 24 days CT feeding was significantly higher (91.4 ±1.2) than 15 days (82.5 ±2.7) of carp testis feeding.DOI: http://dx.doi.org/10.3126/on.v12i1.12251Our Nature (2014), 12(1): 1-7