bluuebunny/crossref_metadata_2025_split huggingface dataset:
CO2 Management at ExxonMobil's LaBarge Field, Wyoming, USA
Authors: Parker Michael Edward , Valencia Jaime , Northrop Scott , Foglesong Bob , Duncan William Thomas 
Published: May 2016

Abstract
Production of natural gas from the LaBarge field in southwest Wyoming began in 1986. This gas contains high concentrations of carbon dioxide (CO2), and from the very beginning, ExxonMobil has successfully implemented several technologies and approaches to effectively manage the substantial volumes of CO2 associated with its production. Many of the technologies and approaches used for managing CO22 at LaBarge are examples of technologies and approaches being proposed for use in carbon capture and storage (CCS) by other industries.
The Shute Creek Treating Facility (SCTF) processes the gas produced from the LaBarge field. The SCTF handles the lowest hydrocarbon content natural gas commercially produced in the world. The gas composition entering Shute Creek is 65% CO2, 21% methane, 7% nitrogen, 5% hydrogen sulfide (H2S) and 0.6% helium. The SCTF separates CO2, methane, and helium for sale and removes hydrogen sulfide for disposal.
Most of the CO2 captured at Shute Creek is used for enhanced oil recovery (EOR). EOR is consistently cited as one of the most viable early opportunities for large scale implementation of CCS. ExxonMobil's LaBarge operation is the largest demonstration of this approach to CCS in the world today. Currently ExxonMobil provides 4 to 5 million tonnes per year of CO2 for EOR. Ongoing facility expansion will increase this capacity to over 7 million tonnes per year in 2010.
A concentrated acid gas stream of about 60% hydrogen sulfide and 40% CO2 is injected into a carefully selected section of the same reservoir from which it was produced, safely disposing of the hydrogen sulfide along with approximately 400,000 tonnes of CO2 per year. Other technologies and approaches that have reduced CO2 emissions include the ExxonMobil patented low BTU fuel co-generation system that substantially reduces CO2 emissions when compared to emissions from purchased power.
Cumulatively, through the application of these technologies at LaBarge, ExxonMobil will have the capacity to capture and manage over 75% of the CO2 produced from the LaBarge field.
Case Studies on Simulation of Wax Deposition in Pipelines
Authors: Pan Shu , Zhu Jack , Zhang Dan , Razouki Ali , Talbot Mike , Wierzchowski Scott 
Published: May 2016

Abstract
The problem cased by wax deposition during production and transportation of waxy oil has been receiving an increasing attention from the industry, especially with the off-shore projects expansion recently. Due to the high cost of those projects, an accurate modelling on wax precipitation and deposition is imperatively required to facilitate the design, development, and operation of those projects. While the wax precipitation models depict the thermodynamic behaviour of waxy oil, the modelling of wax deposition in production facilities and pipelines focuses on how soon wax would accumulate. The wax deposition simulation appears to be a more challenging task due to the high complexity and limited measured data available in the open literature. In this work, a compositional simulator is introduced to simulate the wax deposition in a pipeline. This model is founded on a thermodynamics model from our previous work and equipped with major wax deposition mechanisms as well as tuning function. Through four case studies, the model, with its prediction and tuning capability, has demonstrated a practical tool in flow assurance simulation. The results also suggest that a promising methodology can be applied in flow assurance study when the simulator is tuned with measurements from the high pressure deposition cell.
Novel Fracturing Technique Inhibits Post-Fracturing Water Production
Authors: Abdel Meguid Ahmed Ali Mohamed , Waheed Syed Arshad , Yassine Rami , Salem Mohamed , Abd El Aal Ezz El Din Mohamed , Tucker Richard 
Published: May 2016

Abstract
Hydraulic fracturing has been extremely successful in the western desert of Egypt, with approximately 85% of the production resulting from the use of this stimulation technique. However, in many cases the proximity of producing zones to underlying (or overlying) water zones can be a deterrent to fracturing. In the absence of geological barriers, the fracture height can grow uncontrolled during a fracturing treatment into the water-bearing interval and cause unwanted water production. Excessive water production can be detrimental to the economics of a well. By shortening the well's production life and increasing disposal and lifting costs, excessive water production can be extremely detrimental in marginal fields.
This paper presents case histories in which wells were hydraulically fractured using conventional techniques, resulting in higher than 60% water cut, even as much as 100% in one case. While using the conformance-while-fracturing (CWF) method, the water cut was as low as 4%, even when the adjacent water zones were within 20 ft of the perforations. This technique provides a tremendous boost to the economics and an effective solution to a field otherwise plagued with water overproduction. The CWF technique incorporates a relative permeability modifier (RPM) in the fracturing-fluids design. The RPM results in a reduction of effective permeability-to-water without significant changes to the relative permeability-to-oil. This paper describes the geological environment of the El Dour field and discusses properties of the RPM, the CWF job-design considerations, its field applications, and post-fracturing results in comparison to offset wells fractured conventionally. These techniques might be beneficial to other companies faced with similar water-production challenges.

Introduction
As the world's oil-energy demand increases, challenging reservoirs are now being explored. One of the biggest challenges is the water production that normally accompanies the hydrocarbon production. The water can trap the oil and leave huge hydrocarbon reserves unrecovered and also accelerate the fines-migration problem. During well completion, water can increase the chances of corrosion to the surface, downhole tubular, and the chances of scale formations, which can be very difficult to remove once formed (Curtice et al. 2008).
An example of a challenging reservoir is one that does not produce normally without hydraulic-fracturing treatments and has water zones very near to the hydrocarbon zone.
Once these reservoirs are completed using hydraulic fracturing, the water production increases. The problems caused by the water production can be difficult to solve. The case presented in this paper involves one of these reservoirs located in southern Cairo in the western desert, called El Diyur field.
Integration of high resolution 3D seismic and long horizontal well data for predictive structural modeling of the tight Cretaceous Kharaib B reservoir in the Al Shaheen Field, Offshore Qatar
Authors: Prin Cindy , Pedersen-Tatalovic Radmila , Wendorff Maj , Hoch Esbern , Emang Michael Ipui 
Published: May 2016

Abstract

Summary
Detailed structural interpretation has been performed to support development of tight and thin accumulations in the Al Shaheen Field, offshore Qatar. The structural modeling has been improved by integration of new high resolution seismic data and long horizontal well data from the Cretaceous reservoir sequence.
Seismic evaluation has shown a relationship between Permo-Triassic structural elements and subtle structural elements in the Cretaceous section. Horizontal well data has provided structural modeling details beyond seismic resolution linking seismic and reservoir observations to reservoir flow unit scale. The integration of the two data sets has resulted in an improved predictive model of fault zones. Individual fault vertical throws of less than 10 feet have been observed associated with natural fracture systems and topographic features such as abundant local circular depressions.
The integration of seismic and well data has allowed building a detailed predictive model providing key input to the challenging development of the thin and tight Cretaceous reservoirs in the Al Shaheen field.

Introduction
The dominant structural features in the Al Shaheen field comprise a conjugate fault system of E-W main strike direction and a less pronounced NNW-SSE striking component. Parts of the field further display well developed northward down-stepping fault blocks. The vertical throws on the faults in the Cretaceous section are generally less than 10 ft, not directly resolvable in seismic. The seismic structural interpretation was carried out with emphasis on faulting in the homogenous Kharaib B carbonate reservoir to allow integration with well data.
The development of the Al Shaheen field includes more than 200 wells positioned in a tight well spacing with ultra long horizontal wells, including world record well length of 40,320 ft, logged with electric petrophysical evaluation tools. The majority of the horizontal wells are drilled in the Cretaceous Kharaib B reservoir comprising platform carbonates. The reservoir characteristics are particularly suitable for detailed structural interpretation from well data as a result of field wide lateral correlation of thin stratigraphic units.
Drilling Rig Fuel And Emissions Reduction Through Regenerative Braking, Load Leveling And Grid Drilling
Authors: Ahmed Shehab , Tafreshi Reza , Palazzolo Alan , Tucker Randall 
Published: May 2016

Abstract
In this paper, we propose to increase the efficiency of drilling rigs DR, through measurement, modeling, adjustment of DR operation, and incorporating an energy storage flywheel system FW resulting in significant reductions in fuel consumption and pollutant emissions. In this regard, we propose to: a) Develop a full system model of all power producing and consuming machinery and process components in the DR and utilize some system measurements and a neural net based identification approach to best fit the model to test data. b) Utilize the model in (a) to investigate alternative operation modes for the drilling rig to reduce fuel consumption and the resulting air pollutants. The model will also guide integration of an energy storage flywheel FW system into the drilling rig to replace a diesel generator DG in order to operate the remaining DG's at more efficient power levels and yet still handle peak power events with the energy stored in the FW. The model will also be employed to simulate charging of the flywheel from the braking energy as a result of inserting (tripping) the drillstring DS into the hole, and the subsequent use of this renewable energy for powering circulation such as pumps, drawworks, lights.

Introduction
A challenge encountered with electric grid drilling EGD is that utilities levy significant surcharges on peak power demand. The flywheel system FW can charge at a constant low power rate from the grid over a long period of time and then discharge its stored energy at the intermittent, transient, high power levels required by the drilling rig. An example of this is that the power required to raise or lower the 250,000 lb drillstring DS by 90 ft. in 20 seconds is approximately 1.5 MW (2,000 hp), even neglecting electrical and mechanical losses. The FW reduces surcharge cost and EGD reduces NOX since power plants emit about 1/25 of the NOX produced by a diesel generator DG for the same amount of electrical energy (MW Hrs).
Technical and Economical Aspects of Self Healing Coatings
Authors: Hatami Boura Saeed , Samadzadeh Mahdi , Peikari Mahmoud , Kasiriha Mahmood , Ashrafi Ali 
Published: May 2016

Abstract
Corrosion in the oil and gas industries is one of the major concerns of the managers and engineers as the main destructive process that lead to huge economic losses. Among all protective methods for corrosion prevention/control, the use of coating systems applied to a metal surface is most important and applicable solution to provide a dense barrier against the corrosive species and postpone their contact with the metal surface. But self healing coating can be considered as an alternate route to further improve the corrosion protection of metals. Self healing coatings are engineered to provide a superior resistance to corrosion on demand when the coating is breached or stressed or when an electrical or mechanical control signal is applied to the coating. Various approaches for achieving healing functionality and the constituents of these coatings and their roles are introduced and discussed. It is tried to some positive or even negative aspects of applying this coating type are mentioned in detail and the most important of them that can have critical effect on economy and industry are introduced.

Introduction
Results of a study, entitled "Corrosion Costs and Preventive Strategies in the United States," which was conducted from 1999 to 2001 by CC Technologies Laboratories, Inc., with support from the FHWA and NACE show that the total annual estimated direct cost of corrosion in the U.S. is approximately a staggering 3.1% of the nation's Gross Domestic Product. It reveals that, although corrosion management has improved over the past several decades, the U.S. and also other nations must find more and better ways to encourage, support, and implement optimal corrosion control practices. "Implement advanced design practices for better corrosion management" and "Improve corrosion technology through research, development, and implementation" were two of three technical suggested strategies that can be used for better corrosion prevention/management. Corrosion in the oil and gas industries is also one of the major concerns of the managers and engineers as the main destructive process that lead to huge economic losses. Both upstream and downstream parts face this problem and the companies spend billions of dollars in this case. To remain competitive with the world market and win the game, this cost must be kept to a minimum and here the large demands for reliable corrosion preventive methods do exist which we can use in our decision making.
3D Stochastic Stratigraphic Well Correlation of Carbonate Ramp Systems
Authors: Lallier Florent , Viseur Sophie , Borgomano Jean , Caumon Guillaume 
Published: May 2016

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

1) Introduction
In the static and dynamic workflow of carbonate reservoirs, stratigraphic correlation of well data is one of the first and most influent steps. Indeed, facies distribution and petrophysical properties mainly control flow simulation and are often computed thanks to geostatistical methods, on grids based on stratigraphic correlation and structural data interpreted from seismic data (Borgomano [2008]). In reservoir uncertainty modeling approaches, a unique grid is built, and uncertainties about layering geometry, facies distribution and petrophysical properties are handled using multiple geostatistical simulations (Charles et al, 2001). This article aims at assessing uncertainties due to stratigraphic correlations by also generating several set of possible stratigraphic well correlations. Several grids may then be built from these results and used for facies and property modeling. The method presented here generates automatically and stochastically sequence stratigraphic correlations of carbonate ramp systems by hierarchically integrating multiple pieces of 3D information as: interpreted well data,correlation lines extracted from seismic, andinformation obtained on analogs.

2) 3D Stochastic Stratigraphic Well Correlation method
To perform the correlation, we propose a multi-dimensional and stochastic extension of the Dynamic Time Warping Algorithm (DTW, Myers et al., 1981) that we call msDTW. The DTW algorithm provides a way to find the optimal alignment between two time series [Myer et al., 1981]. This algorithm was used for the correlation of two wells by Smith and Waterman [1980], Howell [1983], Waterman and Raymond [1987], Griffiths and Bake [1990], Brown [1997] for example. Lallier et al. [2009] presented an improvement of the DTW, making the method stochastic and introducing a hierarchy to mimic the reasoning made by sedimentologists when correlating well data (Fig. 1), and applied this method to a carbonate ramp system.
Effect of LoSal on Wettability and Oil Recovery of Carbonate and Sandstone Formation
Authors: Zekri Abdulrazag Yusef , Nasr Mohamed Sanousi , Al-Arabai Zaid Ibrahim 
Published: May 2016

Abstract
Modification of injection water salinity to improve oil recovery is not a new idea and the process has been investigated as far back as the 70's prior to the use of other chemical processes to improve oil recovery. In practice in planning water flooding project oil companies focused only on the compatibility of injection water and formation water issue to eliminate any possibility of formation damage. Many investigators recently had focused their research on the role of water salinity alteration to improve oil recovery. A number of possible mechanisms concerning alteration of water flooding salinity have been proposed in the literature. This project describes an experimental investigation of contact angle changes as function of time, and water flood performance using limestone and sand stone rocks for various injection brines. Carbonate rocks, sandstone rocks obtrained from a Libyan oil reservoir, high salinity water, sea water, low salinity water, and water contains different sulfate concentrations were employed in this study. The results of this research will shed more light on the mechanism of modified salinity flooding (MSFTM) and will help operating companies to better plan water flooding process.

Introduction
Water flooding has been used for many years to improve recovery from oil reservoirs. In the past, no attention has been given to the effect of the water composition and/or concentration on the possibility of increased oil recovery by alteration of salinity type and concentration. Historically the engineering design of water flooding focused only on avoiding formation damage by making sure no interaction between injected brine and indigenous brine. Morrow et al. (1996) concluded that alteration of brine composition of injected water can result in optimization of oil recovery. Tang and Morrow 1999; and McGuire et al. 2005, investigated further the effect of salinity on oil recovery and they have proved that decreasing brine salinity can improve oil recovery. Jerauld et al. 2008 indicated that more than 20 core floods using low salinity of sandstone reservoirs at reservoir conditions and at secondary and tertiary modes has been reported in the literature. Results of experimental work demonstrated an improvement of recovery efficiency due to low salinity by 5 to 38% and that manifested by reduction of residual oil saturation by 3 to 17% pore volume. Nasralla et al. 2011, indicated that injection of deionized water in the secondary mode resulted in a significant improvement in oil recovery compared to seawater.
Different hypothesis have been introduced to explain the improvement in oil recovery by low salinity water injection. These include interfacial tension reduction, wettability alteration, change in pH (increase) resulting in in-situ saponification, emulsion formation, and clay migration.
Optimized Planning and Placement of Horizontal Wells Improved Well Productivity and Controlled Water Cut in Umm Gudair Field, Kuwait
Authors: Banerjee Tapan Kumar , Fadli Eman Hadad Eaid , Ahmed Fazal , Al-Khalifa Nasser 
Published: May 2016

Abstract
Minagish Oolite reservoir of Umm Gudair field, West Kuwait is a cretaceous carbonate reservoir having active aquifer support. Maintaining plateau rate of production with infill drilling is constrained by increasing water cut due to absence of effective stratified layers. Many of the traditional water shut off techniques and selective perforations were partially successful in delaying upward movement of water in wells. But the recent horizontal drilling activity initiated in past 6 years has improved productivity and reduced water cuts in wells.
The selection of well location, trajectory designing and placement of horizontal wells remained a great challenge for UG field. The stress field study, barrier identification and continuous tracking of oil water contact have played important roles in location selection and proper placement of horizontal wells. In UG field all wells are completed with Electrical Submersible Pumps, which dectates dog leg severity of hole and casing designs. Additionally, the higher-up lost circulation zones in Shuaiba and caving shales of Ratawi section restrict early kick off and special mud policies. In the reservoir section, GR and Resistivity responses are monotonous and pose challenge for geosteering. Hence, Image log of LWD tool has been successfully used in picking bed boundary and formation dips to place the trajectory in desired zones.
The evaluation of horizontal well performance in UG field suggest that consideration of critical parameters at planning stage has helped in achieving improved productivity and controlling water cut in wells.
The paper demonstrates how proper understanding of reservoir dynamics and reservoir characterization along with multidisciplinary synergetic approach can lead to a successful horizontal well.

Introduction
The UG field of west Kuwait is mainly a carbonate reservoir, discovered in 1964, produces from the Lower Cretaceous-Middle Minagish formation. The reservoir informally known as the Minagish Oolite (MO) is structurally consist of two doubly plunging anticlines, eastern part is known as EUG and west is called WUG which are connected through a saddle area in middle. About 1/3 of the structural area located in the south (SUG)2, falls in Partitioned Neutral Zone (PNZ) where KGOC and Saudi-Texaco companies are joint partners. The Fig.1 shows the 3D structural view of the area and Fig. 2 shows the oil column in cross section perspectives.
A Combination of Perforating Technologies to Maximize Well Productivity and Minimize Rig Time
Authors: Chadha Nishant , Baumann Carlos Erik , Williams Harvey Alec Rodney , Yokote Ryosuke 
Published: May 2016

Abstract
In this paper we describe the challenges and the techniques used to deliver zero perforation skin wells in the Blacktip gas field offshore Australia. We describe the software models used to evaluate both the well perforation design and the operational risks, and the approach used to reduce rig time. Software modelling based on historical experimental data and newly developed rock perforating models, showed that cleanup with dynamic underbalance would deliver the highest well productivity. Minimum rig time utilization was achieved with wireline conveyed guns. Two methods of deployment were used. To perforate long intervals quickly and safely guns were conveyed on wireline and anchored in the casing with a system that automatically dropped the entire string into the sump after firing. This technique requires less rig time, but it is only applicable to wells with a total gunstring weight lower than the wireline safe working load. The second technique for multiple spaced out payzones used conventional, multiple wireline trips.
All relevant aspects of the perforating jobs, including gun carrier filling after firing, wellbore pressure waves, reservoir flow, and perforation tunnel cleanup were predicted. For each job, guns were custom loaded so as to produce enough dynamic underbalance (DUB) to remove the low permeability crushed rock zone around perforations, thus minimizing perforation skin and maximizing well productivity.
The Blacktip wells were safely perforated for Eni Australia. In addition, we achieved the objective of zero perforation skin and saved more than one day of rig time. The technologies described in this paper can be applied worldwide, saving significant amounts of money and delivering highly productive wells.

Introduction
The Blacktip field is located in the Timor Sea, Australia, approximately 110 km offshore in the Bonaparte Basin, at a water depth of 50 meters.