bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Ultrasonic Cased-Hole Imager for Enhanced Cement Evaluation
Authors: van Kuijk Robert , Zeroug Smaine , Froelich Benoit , Allouche Michael , Bose Sandip , Miller Douglas , Le Calvez Jean-Luc , Schoepf Virginie , Pagnin Andrea 
Published: February 2016

Abstract
Current acoustic (sonic and ultrasonic) techniques for cement evaluation have proved to be limited in providing unambiguous answers to the zonal isolation issue. This is especially true in lightweight cements where they often fail to differentiate cement from mud. Also, as far as imaging of the cement sheath is concerned, ultrasonic pulse-echo tools fail to image beyond the cemented region adjacent to the casing, thus providing limited diagnosis of the annulus. A new ultrasonic imaging tool has been developed to address these limitations.
The new imager combines the classical pulse-echo technique with a new ultrasonic technique that provides temporally compact echoes arising from propagation along the casing and also reflections at the cement-formation interface. Processing these signals yields unprecedented characterization of the cased hole environment in terms of the nature and acoustic velocity of the material filling the annulus between casing and formation, the material immediately behind casing, the position of the casing within the hole, and the geometrical shape of the hole.
Different wells cemented with conventional and light cements were logged with the new experimental tool. The results demonstrate enhanced cement evaluation for both cement types and significant reduction in the uncertainty in making a squeeze or no-squeeze decision.

Introduction
Cement evaluation logging tools have been used successfully for many years to evaluate casing and cement conditions. These tools, which use sonic or ultrasonic1 techniques, are designed for conventional steel casing and cements. The sonic tools, commonly known as Cement Bond Log or CBL, operate at frequencies of about 20 kHz and measure the amplitude or the attenuation of a wave traveling along the casing. The wave loses energy mainly though shear coupling to the surrounding cement, so that well-bonded solid cement attenuates more quickly than a fluid. Due to the low frequency, the CBL logs made with these tools lack azimuthal resolution, which makes it difficult to distinguish channeling from poor cement properties.
Obtaining Permeability From Seismic Data - A New Breakthrough in Carbonate Reservoir Modelling
Authors: Gartner G.L. Bracco , Wagner P.D. , Baechle G.T. , Sun Y.-F. , Weger R. , Eberli G.P. , Asyee W. , Hillgartner H. , Van der Kolk K. , Leguijt J. , Nasser M.R. , Massaferro J.L. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
Shell's Carbonate Team has been developing a method in which post-stackseismic can be used to estimate average interval matrix permeability incarbonates. The foundation of the technique is a new model, which describes quantitative relationships between sonic velocity, porosity and permeability. This model relates a pore shape factor from the poro-elasticity theory with permeability from lab measurements. This pore shape factor describes the 3Dpore structure and can be extracted from inverted post-stack seismic data. Additionally, this factor relates to pore connectivity and, therefore, to permeability.
After the concept was tested and successfully proven on plug scale, the first implementation focused on a large carbonate field in the Middle East. This accumulation had all the ingredients to perform a full field test of the concept - good thickness for multiple seismic reflections, matrix-dominated permeability, single mineralogy (calcite), superb seismic data and enough wells with good compressional and shear sonic logs.
Introducing pore structures in the characterisation of carbonate reservoirs from acoustic data helps resolve the ambiguity in porosity/permeability prediction. In the test case, we have demonstrated that: the new rock property prediction is much more accurate than properties predicted by commercial inversion packages,pore structure can be extracted from 3- Dpost-stack seismic,a permeability indicator can be estimated from inverted seismic anda permeability indicator volume proved to produce a superior history match against a permeability model constructed from extensive welldata
Application of Wireline Formation Tester (Openhole and Cased-Hole) Sampling Techniques for Estimation of Nonhydrocarbon Gas Content of Khuff Reservoir Fluids in the North Field, Qatar
Authors: Al-Mohsin A. , Tariq S. , Haq S.A. 
Published: February 2016

Abstract
Qatar's North Field is the largest non-associated gas field in the world. The North Field is being developed primarily to supply feedstock gas for a number of LNG (Liquefied Natural Gas) and GTL (Gas-to-Liquid) plants. Accurate determination of the amount of H2S and CO2 in the feedstock gas is critical for the proper design of the LNG and GTL plants. Due to long lead time required for the design and the construction of these processing plants, it is necessary to establish the feedstock gas specifications as early as possible during the FEED (Front End Engineering & Design) process. Moreover, once the plant design specifications are set, early estimation of H2S and CO2 content of Khuff reservoirs at the development well locations is necessary to design a well completion scheme to meet the plant design specification for the feedstock gas.
In 2003, RasGas decided to evaluate several sampling techniques for early estimation of the non-hydrocarbon (NHCG) gas content from Khuff reservoirs. After a thorough study of available options for making reliable measurements of H2S and CO2 content of reservoir fluids using down hole tools, it was decided to test Wireline Formation Testers (WFT), both open-hole (OH-WFT) and cased-hole (CH-WFT) tools, in an appraisal well as a "proof of concept" of these technologies for estimation of H2S and CO2 contents. The results from both OH-WFT and CH-WFT techniques were compared with normal DST surface recombined samples obtained from the same well.
In this paper, the following aspects of OH-WFT and CH-WFT sampling techniques for determining H2S and CO2 contents are discussed and the results/analysis presented:Optimal tool / Sampling bottles / flow line configuration for reducing H2S scavenging effect.Comparative analysis on a relative basis between OH-WFT & CH-WFT samples, both on-site and in laboratory.Evaluation of OH-WFT, CH-WFT and DST sample compositional results on a relative basis.Conclusions / Recommendations.
Assessment of Interwell Communication in the Carbonate Al Khalij Oil Field Using Isotope Ratio Water Sample Analysis
Authors: Danquigny Jacques Albert , Matthews James , Noman Rashed , Mohsen Abdulla 
Published: February 2016

Abstract
Assessment of communication between water injectors and oil producers is a key issue to implement improved oil recovery programs. This paper presents an innovative use of isotope ratio water sample analysis to characterize injector-producer communication and intra-reservoir connectivity in a mature field.
Salt analysis is the standard approach to differentiate injection water from formation water, and assess water injection sweeping efficiency. This requires the brines to have different compositions. However, interactions from the mixing of the two waters or with the formation can prevent reliable information from being obtained from such analyses.
The isotope ratios of water samples are not sensitive to these interactions. This technique is often used in exploration to assess inter-reservoir connectivity at the delineation stage. This paper shows the successful application of isotope ratio analysis to the complex Mishrif carbonate reservoir of the mature Al Khalij field located offshore Qatar. The field has been in production since 1997 and water is injected from a shallow aquifer, while coning from a bottom aquifer is suspected.
In this field, Strontium, Oxygen and Deuterium isotope ratio measurements were carried out on samples collected from a number of wells across the field. This technique enabled us to assess the percentage of injection water produced at each well, and assist in optimizing water injection management.

Introduction

Interwell tracing and water injection
Water injection is the most common secondary recovery process. Injection optimization requires a correct assessment of interwell communication. This is all the more valid in carbonate reservoirs which are commonly fractured; the dynamic impact is usually difficult to assess with static data such as wellbore images or seismic. Production logging or interwell tracing are among the most applied and valuable monitoring techniques to evaluate this impact.
Shell's LNG Technology for 7 - 10 Mtpa LNG Trains
Authors: Buijs K. , Pek B. , Nagelvoort R. 
Published: February 2016

Abstract
The rapid market growth in LNG and the development of large gas reserves such as the North Field of Qatar demand another step-change in the capacity of LNG trains, as lowest unit cost continues to be a key value driver.
With the standard Propane Mixed Refrigerant (C3/MR) technology, capacities up to 5 Mtpa can be achieved with two GE Frame 7 gas turbines as drivers. For higher LNG capacities new configurations are required. Shell has developed designs for both mechanically driven and electrically driven large LNG trains, featuring low cost and low emissions. The choice is determined by project specific considerations.
The Shell Parallel Mixed Refrigerant process consists of a single pre-cool cycle followed by two parallel liquefaction cycles. For pre-cooling either propane or a mixed refrigerant, like in Shell's Double Mixed Refrigerant Process (DMR), is used. With three well proven GE Frame 7 gas turbines, 8 Mtpa of LNG production is achieved. With GE Frame 9 or Siemens V84.2 gas turbines, the LNG capacity increases to 10 Mtpa; these gas turbines are still novel drivers for the LNG industry but are already used as mechanical drivers in other processes.
The Shell Parallel Mixed Refrigerant Process for large LNG trains has a number of appealing advantages:Robustness through the application of well-proven equipment without scale-up of equipment.High reliability and availability by parallel line-up of the liquefaction cycle. For example, if one of the liquefaction cycles trips, LNG production is designed to continue at 60% of train capacity.The optimal power balance between the two liquefaction cycles (1:2) results in a high efficiency.
The application of Shell's electrically driven DMR process is also very attractive. This concept is based on a parallel line-up of the refrigerant compressors around a common set of cryogenic spoolwound exchangers. Electric motors of 65 MW have already been constructed for LNG service. In combination with Shell's DMR technology an LNG production capacity of 8 Mtpa can be achieved. The power station is driven by gas turbines.
Sustained Development in the Pearl GTL Treating Design
Authors: Grootjans Henk 
Published: February 2016

Abstract
Feed gas for Shell's Gas to Liquids (GTL) project in Qatar is supplied from the North Field. Before this sour gas can be processed in the GTL plant it has to be rigorously treated to meet the stringent contaminant specifications for a modern GTL process.
The feed gas contains a wide range of contaminants, including H2S, CO2, several mercaptan species and COS. Treating this gas to specification requires a series of treating processes. These processes have to be selected and integrated to provide a treating complex that is not only cost effective, but also will remove contaminants in an environmental friendly way.
Sustained development has been one of the key elements in the process selection of the Pearl GTL treating units, and this can be clearly seen from the final line-up that has been selected. For the main acid gas removal unit a selective amine process has been chosen. By removing mercaptans in a molecular sieve process, rather than by using a physical solvent the co-absorption of hydrocarbons has been minimized. This improves hydrocarbon efficiency and thus reduces CO2 emissions from burning these hydrocarbons in the sulfur recovery unit is. All sulfur containing streams from the treating units are routed to the sulfur recovery unit, which has been fitted with a special burner arrangement and an integrated tail gas treating unit to maximize the sulfur recovery efficiency over a wide range of feed gas compositions.
The paper provides details on the process selection process taken by Shell Global Solutions, showing the process options that were available and the environmental benefits that were achieved.

Introduction
The Pearl GTL project will be located in Ras Laffan, Qatar and will consist of two trains, which together will produce 140,000 barrels of middle distillates and base oils from natural gas using Shell GTL technology. In addition the plant will produce significant quantities of condensate and LPG. The Pearl GTL project has completed the FEED design phase. Start-up of the project is targeted for late 2009.
Khuff Gas Condensate Development
Authors: Whitson C.H. , Kuntadi A. 
Published: February 2016

Summary
This paper addresses some key reservoir and production issues related to gas and condensate recovery from Khuff reservoirs in the Middle East – namely Ghawar Khuff, North Field and South Pars. These fields represent somewhere between 1,000 and 2,000 Tcf initial gas in place, with 30 to 70 billion barrels of condensate in place. We apply engineering methods and reservoir simulation to quantify the expected performance of Khuff gas condensate fields for a realistic range of geologic description, petrophysical and fluid properties, and production facilities based on published information.
We review key data for reservoir and production design, summarizing the impact of geologic zonation, areal and vertical communication, mean permeability and its variation, relative permeability, water encroachment, and fluid composition on field performance. Because most commercial development projects involving gas sales export are based on delivery contract quotas (DCQs) of 1–1.5 bcf/D for up to 25 years, well-average plateau length and rate-time is used as a primary measure of performance.
We try to describe the interplay of reservoir and production-facilities performance on overall design of field deliverability and total well requirements. Other production issues not considered in our work but with significant impact on Khuff development strategy include gathering system design, rate metering, platform vs. onshore processing, and single-phase vs two-phase pipeline flow. Economics are not considered in our evaluation.
We estimate deliverability impairment from condensate blockage using relative permeability models that reflect the impact of velocity (capillary number improvement and inertial effect). The velocity effect is particularly important in Khuff wells because of the high-k, low-h layers with unusually-high flow velocities and convergent flow.
Layer vertical and areal connectivity can have a profound effect on water encroachment. When sufficient lateral continuity exists, even small aquifers can result in rapid water encroachment through thin, high-permeability zones. This has been studied and is shown to have a lesser effect in Khuff reservoirs.
Physics-Based Well Design - Engineering the Well for Production
Authors: Kline William E. , Dale Bruce A. , Kumar Rahul , Clingman Scott , Asmann Marcus , Rosenbaum Darren F. 
Published: February 2016

Abstract
Ensuring long-term well integrity and optimum completion performance is important for the economic development of any field. However, as fields are now developed with fewer wells and in more technically challenging environments, new technologies are required to deliver mechanically robust and reliable wells that can be operated at the high rates required to meet today's aggressive production targets. Unfortunately, in this environment, our industry can no longer rely on historical industry practices that are based on generalized principles, aggregate historical data, anecdotal evidence, and simplified analytical models, because the inherent inaccuracy of these types of analyses requires excessive use of a significant safety factor between the planned production rates and the actual deliverability limit of the well.
To address this challenge, ExxonMobil has developed unique, physics-based, completion design and well performance modeling capabilities that are applied during both well planning and production phases to optimize overall well performance.
For example, the ability to accurately model the coupled-physics effects of reservoir compaction, sand production, subsurface shear/slip, completion tubular deformations, and various near-well flow impairment effects enables targeted management of critical mechanical integrity and flow capacity issues. More importantly, these models have provided predictive technologies that have resulted in significant business advantage, as ExxonMobil has developed the capability to quantitatively transform these highly complex issues into well defined, and easily applied "technical limits," which establish the boundaries between conservative, optimum, and potentially detrimental well design and production operations. Practical application has been facilitated by defining these limits in simple terms, including reservoir depletion and/or well drawdown.
The incorporation of advanced physics and the corresponding coupled-physics interactions into modeling, simulation and decision-making processes, enables accurate, definition of well performance technical limits and the ability to produce a well right up to these limits. These physics-based production guidance tools provide the technical basis from well design to choke management, enabling more aggressive production with confidence, without risk of failing or impairing wells unnecessarily.
Impact of High-Quality Seismic on the Field Development of a Mature Supergiant Cretaceous Carbonate Field - Onshore Abu Dhabi
Authors: Boekholt M. , King R. , Al-Hamedi A. , Al-Shekaili F. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
The first field discovered in the ADCO concession came on stream in 1963 and is one of the largest Hydrocarbon accumulations in the UAE. In 40 years of production about 700 boreholes penetrated the main reservoirs, however virtually no seismic was acquired over the field.
In 2001, the decision was taken to acquire high-quality 3D seismic across the field after extensive field tests to optimize acquisition parameters and after incorporation of the learning's on the 3D seismic imaging in other ADCO fields. The actual seismic acquisition took 2 years over an 1800 km2 area with640 fold coverage in 12.5 m * 12.5 m bins. It resulted in an extremely high-quality dataset. Extreme care was given in processing to preserve amplitudes and frequencies to enable quantitative seismic attribute analysis. The seismic offers the unique opportunity to study a Middle East Carbonate reservoir after 40 years of production at an unmatched resolution of 100 Hz bandwidth at target level at 3 km depth.
Conventional interpretation started in conjunction with advanced seismic analysis (inversion & forward modeling while the data processing was still ongoing. The studies indicate that information on structure, rock properties and fluid effects can be extracted from the seismic to a much greater detail than possible in any other seismic dataset of ADCO. So far, immediate impact on the field development was obtained as:several fault systems were observed and tied to the main orogenetic phases of the Arabian plate; inclusive of the Paleozoic and Proterozoic trends. Faults can be observed on seismic down to a throw of 5 ft and were confirmed by drilling results.depositional geometries and stacking patterns within the main Carbonate reservoirs were detected. They were used to develop new insights into the reservoir depositional cycles;Flat spots at the edge of the field and water-indicating isochron values around water injectors in the main reservoirs strongly suggest that fluid effects appear to be visible. Analysis on well and seismic data indicates that the effects of porosity and fluid change on the acoustic impedance can be separated in the studied Carbonate reservoirs.
Realizing the Potential of Marginal Reservoirs: The Al Shaheen Field Offshore Qatar
Authors: Thomasen Jakob Bo , Al-Emadi Ismail Abdullah , Noman Rashed , Ogelund Niels Peter , Damgaard Anders Peter 
Published: February 2016

Introduction
The oil bearing reservoirs of the Al Shaheen field, Block 5 offshore Qatar were discovered in the mid-seventies in connection with appraisal drilling on the underlying North Field Khuff gas accumulation. However, at the time, development of the Lower Cretaceous Al Shaheen reservoirs was deemed unattractive due to their limited thickness and tight nature.
Development of the reservoirs commenced in 1992, when Qatar Petroleum entered into an Exploration and Production Sharing Agreement with Maersk Oil Qatar AS.
This extended abstract presents highlights of the development and describes some of the technological advances, which have been applied to attain a commercially viable development.

Challenges
The giant Al Shaheen field comprises a series of thin, stacked reservoirs, dominated by tight carbonates with more permeable carbonate facies occurring over a limited part of the field. The reservoir sequence further comprises a very thin sandstone unit of variable quality.
Following the discovery of the Cretaceous oil accumulation in 1974, a number of appraisal wells were drilled by various operators and comprehensive studies were conducted at the time in order to establish the feasibility of development. However, well tests in the vertical appraisal wells yielded discouraging results and it was concluded that development was not economically feasible.
The main problem was that the majority of the oil in-place existed in thin carbonates with low permeability. Combined with a relatively high oil viscosity, the vertical wells were unable to sustain natural flow and gave very low rates with artificial lift. Further, the hydrocarbon distribution was identified to be governed by non-horizontal fluid contacts due to considerable lateral pressure gradients in the liquid phases. This made prediction of the extent of the accumulation challenging.
Another difficulty was that the reservoirs covered substantial areas, and development would require a very large number of platforms, each connecting to a limited oil in-place volume. This was further aggravated by the fact that the individual reservoirs did not overlay completely but rather spread over different areas.