bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir Characterization from Gas Ratio Analysis Using New High Efficiency Gas Extraction System
Authors: Zhou Leifeng , Blue D. Duncan 
Published: March 2015

ABSTRACT
Mud logging gas detection and chromatography have been traditionally used as indicators of hydrocarbon occurrence and wellsite safety. However, the application of mud logging gas as a reliable reservoir characterization tool had previously been hindered by its semi-quantitative nature, noticeably the inability to get repeatable responses in all environments so that the analysis can be used as a trusted analytical tool, regardless of gas trap operating conditions and surface environments.
A new gas extraction system, Constant Volume Gas Trap (CVGTTM), is now available at wellsite and has been successfully run worldwide. Equipped with several innovative features, CVGT not only improves mud gas extraction efficiency, but also reduces the effects of environmental and operation conditions on quantitative gas measurement. Coupled with high accuracy and a fast cycle gas chromatography system, CVGT gas ratio analysis provides a cost-effective approach to evaluate reservoir fluid types, contacts, and other critical information needed for subsequent fluid sampling, testing, and development programs.
Several applications of gas ratio analysis are presented that complement other reservoir characterization tools and approaches. Vigorous data QC are enforced to reduce the effects of any non-reservoir fluid contributions. Most suitable ratio cutoffs are determined for the target reservoirs. These cutoffs are determined through a variety of factors, in particular the known reservoir fluid properties from offset wells in the area. C1/sum(C1~C5), and the combined use of gas wetness ratio (GWR) and light heavy ratio (LHR) have proved to be the most valuable out of all the gas ratios investigated. Together with total gas and gas chromatography, these ratios and ratio combinations are able to indicate the occurrence of reservoir zone, the types of fluid in it, and the fluid contacts. Fluid types defined from ratio analysis are correlated with LWD/wireline data, particularly the resistivity, cross-over of neutron and density, and pressure gradient analysis. This ultimately leads to better reservoir characterizations with regards to its vertical connectivity, compartment and caprock efficiency, etc.

INTRODUCTION
Accurate reservoir characterization in terms of accurate fluid type, contacts, and vertical evolution and compartmentalization at the early stage of well construction is vital for guiding subsequent fluid sampling, completion, well testing, and production planning and designing. It is also critical to identify the rock and fluid properties accurately in real time to maintain the well in an optimal trajectory for maximum productivity. Such endeavors are often not trivial, especially in producing reservoirs where complications arise due to altered gas/oil/water contacts from virgin status. Such alterations of contacts often result from combined effects of gas cap expansion, continuing production, and water injection.
Optimization Method for Line Pipe Selection & Sizing (A case study from Saudi ARAMCO water injection system)
Authors: Al-Mahamidh Hadi Salim , Al-Khalifa Mohammed Hussain , Dajani Hatem A. 
Published: March 2015

Abstract
This paper intends to address the proper method for carbon steel pipe-sizing using Barlow's Formula as the initial step in pipe-sizing mechanism; and how this formula will assist us to select the proper grade of line pipes. The paper proposes that the grade of the carbon steel line pipe has to be determined first, and the sizing of the carbon steel line pipe has to be determined second. The proposed method for selecting the proper grade of line pipes comes from personal experience with surface water injection in Saudi Arabia.

Introduction
Pipelines are major facilities in oil industry; most are metal types of carbon steel. Millions of US Dollars have been spent on funding projects of carbon steel pipelines. In light of changes of world economy where prices of carbon steel line pipes have increased dramatically, either due changes in cost of energy used for manufacturing the line-pipes, or else. As engineers, we have to re-examine requirements and specifications in order to change them to meet the essential requirements and continue using carbon steel line pipes at fair cost. This can be achieved once the proper grades of line pipes are being selected without over sizing in the requirements.

Material Strength
The strength of any metal material is determined by the tension test, which measures the tension force and the deformation of the test specimen. The stress which gives a permanent deformation is the yield strength. The stress which gives rupture is the ultimate strength. Figure-1 shows the common stress-strain curve. Figure-2 shows the yield strength and the ultimate strength of the most common line pipes used in the industry.

Discussion
The Barlow's formula is not totally new for uses in pipe-sizing. It has been used in every day applications for determining pressure rating of pipes. Also, it has been used with other fluid equations in hydraulic and simulation applications. However, with software available today for hydraulic simulation, we tend to overlook such simple formula and rely on the hydraulic software to perform the sizing calculations, ignoring the selections of the line pipes grades, and the differences between these grades of line pipes. Fortunatly, any grade is often made in all sizes, and that is why we do not pay much attention to the type of grade that would be used in a project as long as we can get the pressure rate and the size we need. Therefore, it is advisable that line pipe grade be selected based on the pressure rating of the system at first; then the hydraulic simulations or other fluid measurements can be utilized for determining: the proper size or any further sizing, fluid velocity, delta pressure, or other fluid parameters that have to be evaluated.
The Influence of Geological Heterogeneities on Well Productivity: Simulated Outcrop Analogue
Authors: Al-Oreibi Lama Abdul Nasser , Reijnders Gert-jan C.A. , Jennings James W. , Carter Sam , Poppelreiter Michael , Zampetti Valentina , Dawans Jean-Michel Laurent 
Published: March 2015

Introduction
What level of geological detail is required to give a meaningful representation of a reservoir model? Is it worthwhile to spend the time, money and effort to assemble a high-resolution geological model or will simpler models suffice? How coarse can a model be to provide the fastest possible execution while simultaneously preserving enough geological detail for realistic performance predictions?
To answer the holistic question of how much resolution needs to be preserved, a high resolution geological model of an outcrop of the Khuff formation (Oman) is used to develop a methodology to assess the impact of the preservation of geological heterogeneities. Sensitivity tests to various grid sizes have been carried out to determine what level of detail needs to be retained to achieve representative well production forecasts.
3D Seismic Attributes, A tool for well Placment in Complex Reef Build-up
Authors: Najia Walid , Bellah Samir , Al Shehhi Jamila 
Published: March 2015

Abstract
This middle cretaceous reef build up reservoir has similar problems to other fields of similar setting in the region, regarding upper contact in the form of Karstification with a mixture of fill, shally interbedding, lateral / vertical tight intervals, uneven Vug distribution and large transion zone.
Those have presented a great challenge to adequately place horizontal wells, where near surface well path will intercept the Karst topography extending in the reservoir with its potential drilling hazard while away from the surface wells will end up in high SW zone. In this context, well placement becomes a real challenge. Few wells had to be plugged and side tracked adding several million dollars to the drilling cost beside the lost in hole equipment.
After our 3D OBC seismic survey, the team attempted and succeeded in using (for the first time) a group of seismic guided Reservoir characteristic attributes to identify a sweet spot (in our case a sweet level) and develop a well path plan that properly placed the well trajectory deep enough away from Karst and surface irregularity avoiding the danger of drilling hazard and penetrating the upper layer, yet shallow enough not to fall within the high water zone.
Our success story is supported by wire line image log and acoustic logs and keeping the well cost at reasonably estimated values.
The paper reviews difficulty normally faced in drilling those wells, summarize original work carried out in selecting seismic guided attributes (as part of the reservoir characterization) to build a well design based on those findings. The paper will finally present a successful drilling case of 2700 ft supported by wireline logs.

Introduction:
The field is located in offshore Abu Dhabi and has been producing for the last 25 years. It covers about 400 Km2. The producing reservoir consists of series of middle cretaceous culminations covering almost the entire field. It is a reefal and shoal limestone build-up characterized by a typical thick bottom water drive reservoir. The dry oil interval is relatively thin and sited above huge transition zone.
Since the field discovery, over 60 vertical, deviated and horizontal wells were drilled in the field as oil producers and water injectors. Many other wells were side tracked to be horizontalized for maximum reservoir exposure.
SIMOPS During Construction, Commissioning, Startup, and Operation of the World's Largest LNG Project
Authors: Schmidt Kevin 
Published: March 2015

Abstract
This paper will highlight the best practices and lessons learned from Qatar Liquefied Gas Company Limited (2)'s (QG2) development and implementation of an onshore Simultaneous Operations (SIMOPS) procedure and organization. It will show the unique steps taken during the construction, commissioning, start-up and operation of the world's largest Liquefied Natural Gas (LNG) process train. These steps ensure minimal impact of simultaneous activities in construction and operation of a live plant.
The complexity of the situation demanded Management commitment, effective communication and a systematic approach including defined procedures and detailed planning while working with independent organizations. This paper will emphasize the importance of well organized and continually monitored SIMOPS programs to the safe and successful implementation of large scale projects with staged turnovers. The programs can also be applied to situations in which there are multiple construction projects in a single area to address interfaces during construction through to start up.
Focus will be on three main areas:The development of a Matrix of Permissible Operations (MOPO) that clearly laid out what activities were allowed to happen simultaneously in the same area or on the same system.The use of a standard Permit To Work (PTW) system facilitated by SIMOPS area plot plans, updated weekly. This allowed for a single transition when switching from the construction PTW system and allowed the operators and the Contractor to become familiar with an Operations PTW as they were both involved with work inside the operating plant. The SIMOPS area plot plans are updated with input from all organizations involved. This input makes it clear who controls specific permits in each area minimizing delays and incidents caused by mismanaged PTW interfaces.The building of an onshore SIMOPS Plan fostering an operations organization dedicated to SIMOPS controls and continuous improvement. This overall plan that lays out the keys to SIMOPS area definitions and the requirements in these areas such as PTW and organizational responsibility was the foundation of QG2's program. Developing the SIMOPS Plan early on facilitated a staged turnover plan for Process Train 4.
Successful Field Application of an Inhibitor Concentration Detection System in Optimising the Kinetic Hydrate Inhibitor (KHI) Injection Rates and Reducing the Risks Associated with Hydrate Blockage
Authors: Lavallie Orlin , AL Ansari Ahmed , O&apos;Neill Stephen , Chazelas Olivier , Glenat Philippe , Tohidi Bahman 
Published: March 2015

Abstract
Currently, hydrate inhibitors are injected at the pipelines upstream based on the calculated/measured hydrate phase boundary, water cut, worst pressure and temperature conditions, and the amount of inhibitor lost to non-aqueous phases. In general, no means of controlling and monitoring are available along the pipeline and/or downstream to assess the degree of inhibition. Often high safety margins are considered to accommodate for the uncertainties in the above parameters and to ensure gas hydrate risks are eliminated. However, despite these efforts hydrates do still form and this can result in considerable economical and safety concerns.
As a result of a joint industry project, a novel device based on electrical conductivity and sonic velocity (C-V technique) has been developed for monitoring the hydrate safety margin to optimise inhibitor injection rates. The system determines the amount of inhibitors (e.g., salt, KHI, methanol, MEG, etc…) in the aqueous phase and the degree of inhibition they can provide.
The device has been successfully applied in determining the amount of KHI in produced water from the Dolphin field in Qatar. Compared to conventional chemical techniques the device is much faster (less than 3 minutes) and less labour intensive and there is no chemical requirement.
In this presentation, the results of the trial of this device in determining KHI concentration in produced water are described. The results shows that this new technique is very fast and reliable, optimising the KHI injection rate, improving the economy and reliability of hydrate inhibition strategy, and minimising the impact on the environment.

Introduction
From a flow assurance point of view, gas hydrate formation is undoubtedly dreaded as the major risk of plugging the oil and gas production systems.

Natural gas hydrates.
Natural Gas hydrates are ice-like crystalline compounds that form whenever water molecules contact hydrocarbon gas molecules of low molecular weight (from methane to butane) or other gas molecules such as N2, CO2 or H2S. The hydrate crystals can be represented as a network of hydrogen-bonded water molecules forming cages with gas constituents trapped within. Conditions promoting gas hydrate formation are high pressure (typically &gt; 30 bar) and low temperature (typically &lt; 20°C). Precise conditions in terms of pressure and temperature depend on the composition of the fluids. Hydrate formation can occur for all the produced fluids if required P & T conditions are reached: natural gas, gas with condensate and crude oil with associated gas, with condensed or formation water.
Deep Fluid Diversion for Profile Control and Oil Displacement Technologies
Authors: Liu He , Hanbing Xu 
Published: March 2015

Abstract
Through 50 years of water injection production, Daqing Oilfield has developed matched chemical and mechanical zonal injection and production technologies. However, due to residue oil scattering here and there, and serious low effective and non-effective circulations happening in high watercut period, the existing profile modification system can hardly meet reservoir requirements. Currently, water injection well averagely serves 3 to 4 intervals, and oil wells mostly produce commingled. It's urgent to realize multi-zone fine zonal water injection, oil well fine production and injection-production well integrity. In later high watercut stage, to enhance water flooding recovery rate is our new challenge. Based on profile control technology, we've developed low cost, long efficiency deep fluid conversion profile control and oil displacement technologies, and high efficiency fine control water injection technologies, which contribute to the accuracy of water injection, and recovery rate rise of 2–3% in reservoirs with watercut above 90%.

Introduction
Most fields in Daqing Oilfield are continentally sedimented with high heterogeneity. With decades of water injection development, the heterogeneity is worsened, and large pores are developed in deep reservoir and near wellbore formations. Along the large pores is the water flow strengthened, and less or no water passes through low permeability zones. What is worse, in deep reservoir formations, the large pores and high permeability zones are enlarged, even water channels are formed, proved by core analysis. As a result, the deep reservoir heterogeneity is getting worse. More and more water passes through the high permeability zones, while the low permeability zones are weakly flooded by water and little oil is moved. High water production from the high permeability zones affects well productivity a lot, as it usually leads to high bottom-hole pressure, which inhibits oil being produced from low permeability zones. Since the high permeability zones have already been flooded largely, the injected water takes little or no effect on moving the remaining oil.
To solve the problem, conformance improvement technique gets in our mind. However, near wellbore profile correction treatment can only improve the heterogeneity in the vicinity of the injector. For high heterogeneity in deep reservoir areas, the technique needs improving. A type of high strength swelling delayed particle and a type of zwitterionic polymer gel are developed in the work and used in the field.
Effects of syn-depositional tectonics on platform geometry and reservoir characters in Miocene carbonate platforms of Central Luconia, Sarawak
Authors: Ting King King , Pierson Bernard J. , Al-Jaadi Omar , Hague Paul F. 
Published: March 2015

Abstract
It is commonly assumed that the Miocene carbonate platforms of Central Luconia, Sarawak developed and grew on a stable substratum. This paper documents evidence of syn-depositional tectonic movements in the 'Mega Platform' in the northern part of the Central Luconia Basin. Detailed 3D seismic interpretation techniques consisting of spectral decomposition, acoustic impedance opacity rendering, and structurally oriented semblance filtering were used to better constrain geological processes affecting, controlling and modifying the evolution and demise of the platform. Syn-depsositional tectonic movements impacting stratigraphy architecture at a scale sufficient to fragment or break up a platform occurred during platform growth. Depending on the magnitude of the movements, carbonate platforms responded in different ways:Platform fragmentation and permanent separation of part of the platform; this happened in the southern part of the mega-platform early on in its growth history. Two smaller platforms separated from the main one and continued growing as separate entities.Step subsidence and infill of new accommodation space; part of a platform subsides but the surviving part generates sufficient sediment volume to fill in the new accommodation space through progradation. A flat platform is eventually restored over the whole or part of the initial platform surface.Step subsidence and contraction of a platform; part of a platform subsides but the surviving platform does not have the capacity to produce the sediment volume required to fill in the new accommodation space. The down-stepped part of the platform eventually drowns.
Faulting not only created topography as a template for the initiation of carbonate platform deposition but also as pedestals for the localization of backstepped platforms. Cessation of syn-depositional faulting may create tectonic quiescence period that instigated progradation as a result of deceleration of accommodation-space production.
Improving SAGD Performance Combining with CSS
Authors: Ghanbari Ebrahim , Mighani Saied , Shaabani Emadoddin , Alipour Reza 
Published: March 2015

Abstract
There are large resources of heavy oil reservoir with high viscosity that cannot be produced by natural depletion. The main obstacle to produce from these large deposits of heavy oil and bitumen resources is the high viscosity of these oils. This large amount of oil can be produced considerably by thermal EOR (Enhanced Oil Recovery) methods. The Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) process has been found as a promising EOR process to recover bitumen and heavy oils.
In this paper, the SAGD and CSS process were combined together to benefit advantages of both methods. When the wells are shut-in to soak, injectivity of steam during SAGD process will increase. So the chamber can extend more easily to drain the oil toward production wells. During this study, possibility and efficiency of this new method was assessed by simulation study using CMG STARS and sensitivity analysis was conducted to optimize the process. The production performance of this method is compared to conventional SAGD and CSS process.
Simulation results show that with the same steam injection rate, this new method has more oil recovery than conventional SAGD, due to better development of steam chamber into reservoir. Also as a result of lower steam-oil-ratio the production cost is reduced.

Introduction
Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) processes have been found as two efficient methods for heavy oil recovery. The Steam Assisted Gravity Drainage (SAGD) using gravity as driving force and a pair of horizontal wells for injection/production ensures both a stable displacement of steam and economical oil production rate [1]. As shown in figure 1, SAGD requires two wellbores. One wellbore continuously injects steam and a second one continuously produces mobilized bitumen and condensed steam. Horizontal wells are used to enhance reservoir access and thus well productivity [2].