bluuebunny/crossref_metadata_2025_split huggingface dataset:
Understanding Production from Eagle Ford-Austin Chalk System
Authors: Martin Ron , Baihly Jason , Malpani Raj , Lindsay Garrett , Atwood W. Keith 
Published: October 2011

Abstract
The US Energy Information Administration's forecast gas price is below USD 5/Mcf through the 2011 calendar year, prompting many historically gas-focused companies to shift their portfolio emphasis to oil. South Texas has been a hotbed for oil development for the last half a century. The last great oil boom in south Texas occurred in the Austin Chalk formation in the 1970s and early 1990s. Today, the Eagle Ford Shale has renewed oil exploration interest in South Texas.
The Eagle Ford Shale is a very prolific play that for the most part is bounded on top by the Austin Chalk formation. Many operators are wondering if the oil being produced from the Eagle Ford Shale is essentially the same oil (from both a source and geochemical standpoint) as the Austin Chalk. Owing to the tight nature of the shale, it is highly unlikely that oil is being produced solely through pore flow into hydraulic fractures. The industry has not fully grasped the storage mechanism in the Eagle Ford Shale and the factors that indicate a good producing area versus a mediocre one.
This paper studies the possibility that the Austin Chalk and Eagle Ford Shale form a single hydrocarbon system. The potential source, generation, migration, storage, and production mechanisms of both formations will be analyzed from a geologic perspective. The implications of this theory for exploiting the Eagle Ford Shale will also be discussed. From a production standpoint, this paper will compare the production trends of horizontal wells in the Eagle Ford Shale and Austin Chalk formations, analyzing each in detail to determine if there are any similarities in initial production rates and decline trends.
This paper investigates the areal extent of production from the Eagle Ford Shale and Austin Chalk formations and discusses their interdependencies. In addition, geological and petrophysical attributes are evaluated to understand this phenomenon. Lastly, this paper describes the key mechanism(s) for oil/condensate flow in these oil-producing reservoirs and how to best exploit these unconventional formations.
A Coiled Tubing Perforating Solution Incorporating a Gun Deployment System and Dynamic Underbalance Technique Improves Well Production in High Angle Deep Gas Wells in Saudi Arabia
Authors: Al Jubran Hasan , Leal Jairo , Al BuHassan Shaker , Bolarinwa Simeon , Kharrat Wassim , Pulson Dave , Barnawi Mazen 
Published: October 2011

Abstract
Saudi Aramco has recently initiated a change in gas well design in the Ghawar field of Saudi Arabia. The new approach is to drill deviated cased hole gas wells through the reservoir to increase the length of contact of the productive zone and thereby increase production potential. Typical gas wells were drilled as a vertical cased hole through the reservoir or open hole horizontal gas wells.
The increased well deviations, measured depths and resultant increase in reservoir sections required a new approach to the perforating solution for these wells to connect them to the gas plants. Various techniques were reviewed, considering safety, operating efficiency and well performance. The final solution was to deploy the perforating systems on electric coiled tubing (CT) and run all the guns in one run using completion insertion and retrieval under pressure (CIRP) as a deployment system, which allowed the guns to be run and pulled under live well conditions without having to kill the well.
This paper details the learning curve and lessons learned from the implementation of this technique in five gas wells. The deployment system and pressure control equipment were optimized to satisfy Saudi Aramco's requirement for three barriers. A CT cleanout run was added before perforation to remove any debris from the wellbore causing a problem to the depth correlation tools. An existing CT tower was used to support the very long wellhead stack, but due to its height limitation a special solution was implemented to enable safe CT operations. A deployment system under live well conditions was used to minimize CT runs, operating time and cost savings. The static underbalance condition was set before running the guns, combined with the dynamic underbalance perforating technique and deep penetrating charge gun design were implemented to optimize the well performance. This technique allowed safe and efficient perforating in a single underbalance run of these five gas wells.
The paper also covers the planning of the perforating solution, health, safety and environment (HSE) considerations, equipment selection, operational procedures, job execution and results.
Threading the Needle: Optimizing Horizontal Wellbores Within Tight Vertical and Lateral Tolerances: A Case Study
Authors: Spotkaeff Matthew , Dolan James , Dupuis Christophe , Saicic Milan , Handels Martijn , Viandante Mauro , Perna Ferdinando , Stueland Eirik 
Published: October 2011

Abstract
The process of geosteering, using real-time logging-while-drilling data to actively steer horizontal or highly deviated wellbores, has been in use for more than 20 years. Over this period, the demand for more sophisticated measurements has developed along with the need to access increasingly difficult reservoirs as the simpler drilling scenarios are being exhausted.
Such a case is evident in the Yme Gamma development, located offshore south-western Norway, consisting of four horizontal producing wells and two vertical injectors. Abandoned by the original operator because of high water cut, to redevelop the field the current operator needed to drill subsequent wells in a narrow corridor up-dip between the existing producer wells and the bounding fault, in the thin YS 7 (4 to 8 m) inner-estuary sands or the YS 5/4 (2 to 6 m) inner/central-estuary sands.
The Yme 9/2-C-2A well was successfully drilled as a replacement for the C-2 well, which had been redrilled because of the reservoir being swept in that area. Since the neighbouring well, C-3T3, showed encouraging results in the YS 5/4 reservoir, which was not targeted in that well, a horizontal well was planned to exploit this reservoir.
There were several challenges that needed to be addressed in the geosteering of this well: the need to keep the wellbore within a narrow reservoir (between 2 and 6m in thickness); a very narrow lateral corridor between the main bounding fault and existing wells; observed sub-seismic faulting in neighbouring wells; and the possibility of a coal layer, which would necessitate a sidetrack if intersected.
As with any geosteering operation, success is often the result of a combination of inter-department team work and communication as well as the use of appropriate technology. Integrated use of a bed boundary mapping device and real-time density images allowed the 9/2-C-2A well to be geosteered within these tight tolerances, skirting the bounding fault by less than 1 m lateral displacement, and allowing for the drilling of other tight tolerance wells.
Cardinal Points to Achieve the Excellence in Horizontal Open-hole Gravel Packing Operations in Deep- and Ultra-deepwaters
Authors: Marques Luiz C. , Pedroso Carlos Alberto 
Published: October 2011

Abstract
In many instances Campos Basin has been a place of milestones in horizontal open hole gravel packing (HOHGP) in deep and ultra-deepwaters scenarios. However, to achieve the excellence in this field, we have continuously fine-tuned our operational practices and procedures to overcome different hurdles, such as: paucity of formation sand distribution analysis, poor understanding of the deposition profile of our turbidites and/or reservoir heterogeneities; poor understanding of gravel transport phenomena, use of newly-developed HOHGP tools (which had not been extensively field-proven yet), inadequate wellbore clean-up procedures, inadequate sand screens, excessive corrosion of screens during post-acid treatments, non-optimized well geometry, poor drilling-in practices, bad-tuned sand placement simulators (we ended-up developing our own one), unsuitable filtration practice, the need to complete - and gravel pack - long open hole wells with low fracture gradient in ultra-deepwaters scenarios and other Gordian knots.
After a somewhat-bumpy beginning, which is typical of any learning process, we have successfully managed to perform circa 350 horizontal long-interval open-hole gravel packs, and 170 frac packs (Statistics of 2011) in Campos Basin. Based on reliable and abundant data we have managed to gather from these operations, we have developed a field-proven bias in favor of gravel packs and frac packs (not a subject of this technical paper) as well. The following are the advantages associated with the application of these sand control measures: a higher-performance completion, a longer mean-time to failure, and a lower skin factor. So, when it comes to sand control, gravel pack and frac pack - wherever they can be applied to - are the first recipes we go for.
In summary, this paper describes the cardinal points to deal with in order to achieve the excellence in HOHGP operations. Case histories and lessons we have learned in this "no two wells are alike" scenarios are discussed as well. Statistics on our well-completion efficiency are also presented. A list of the cardinal points to achieve the excellence in HOHGP is presented below.
The Upstream Professional Development Center (UPDC): The Continuing Evolution of Upstream Professional Development
Authors: Aggour Tamir , Salamy Salam , G. Kersey David , Ghanim Abdullatif 
Published: October 2011

Abstract
This paper presents details of the development and implementation of a new upstream professional development initiative in Saudi Aramco. In response to quickly changing business and demographic environments, the approach to technical training has evolved to ensure a competent workforce that can effectively manage the technical challenges faced in exploration and production operations. The paper presents the business drivers leading to the establishment of a new state-of-the-art training facility and a new upstream training organization, along with details of the implementation of this new initiative. The result is a dynamic training organization that is responsive to evolving business needs, and accelerates the development of young professionals. In addition, experienced engineers and geoscientists benefit from receiving a structured professional development roadmap that spans their entire careers. By incorporating instructional design concepts, advanced training technologies and formal competency assurance, the Upstream Professional Development Center provides engaging, effective and efficient training that accelerates the achievement of competency and improves job performance.
Real Time Sand Production Management Using Non-intrusive Surface Ultrasonic Sand Monitors in TNK-BP Brown Fields in Western Siberia
Authors: Muslimov E. Y. , Medvedev P. V. , Shevchenko S. D. , Mironov D. V. , Afanasiev A. V. 
Published: October 2011

Abstract
The article discusses the conducted pilots in TNK-BP brown fields (Vaniegan, Samotlor) with non-intrusive surface ultrasonic sand monitors to optimize ESP lifted oil well regimes in real time. Existing produced solids monitoring practices in TNK-BP consist of regular sampling and require further filtration lab analysis. This process delays immediate corrective action implementation and provides only sporadic values of sand production. Excessive and abrasive sand production has a strong negative impact on runlife of artificial lift equipment and production systems. Today, ESP MTBF for high sand producers is 46 times less compared to analogue data field averages, which results in increased OPEX. The ultrasonic sand monitoring technology was applied to wells with frequent sand related ESP's failures to mitigate performance. Considered fields have up to 5% of such wells in the total amount. The first stage of the technology testing was a learning curve in installation, interpretation and matching outputs with the lab tests. Second stage included various tests in regulating the wells to achieve optimum balance between fluid and sand production using the surface choke and ESP VSD. Optimization of flow rates to control sand production was verified and backed up by sampling and lab analysis with over 103 tests performed within the pilot activity. Observations showed a significant reduction in sand production was achieved in various cases with minimal impact on fluids production with a trend of irregular sand production patterns observed in most of the cases. Because of the large number of wells in the fields, the new and preferred method of installiation is in the automatic group metering unit was proposed and successfully trialed. Detectors accuracy decreases with velocity below 1 m/s. Not all wells had a response to regulation. The areas for further technology development are related to specifics of on-land operations in Siberia. This includes power supply option improvement, absence of wireless data transfer or memory on the sensor for data storage. The method of real time solids monitoring was trialed for the first time in our company. This allowed discovering new opportunities to optimize performance of high sand producers and to scale up the technology to the other TNK-BP fields in the future.
Drilling and Under-Reaming in the GOM Deepwater Ultradeep Lower Tertiary: History of a Record Run in the World's Deepest Oil or Gas Well
Authors: Ubaru Charles , Thomson Ian , Radford Steven 
Published: October 2011

Abstract
Operators have been drilling deepwater prospects in the Gulf of Mexico (GOM) since the late 1980s. However, technology has evolved tremendously enabling deepwater operators to explore deeper frontiers. Many of the recent promising GOM deepwater prospects are targeting the lower tertiary sedimentary dispersal system that is regionally continuous from the coastal zone to the deepwater basin. Many of these wells seek ultradeep targets with total vertical depth (TVD) ranging from 28,000 - 35,000 ft (8534-10668 m).
To reach these deep lower tertiary reservoirs in the middle Paleocene to early Eocene age (Wilcox Group), operators must overcome many drilling challenges, including wellbore integrity, borehole stability, pressure management, destructive vibrations and suboptimum drill bit and under-reamer performance when drilling at these greater depths.
Due to the nature of the well construction and completion programs of these deepwater ultra-deep wells, which very often require over six casing strings, concentric expandable under-reamers are regularly used to maximize the wellbore final section size.
As these lower tertiary sandstones can be highly abrasive and hard, especially under extremely high confining pressures, bit and under-reamer durability has become a huge challenge. This paper will focus on the deepest successful 12 ¼ -in underreamer run in the world (31,400 ft or 9571 m TVD), achieved when drilling the deepest oil or gas well ever drilled., with emphasis on the selected under-reamer characteristics, bit selection and best drilling practices used.
Remote Operations - A Remote Possibility, or The Way We Do Things ‘Round Here?
Authors: Cramer Ron , Hofsteenge Hetty , Moroney Tom , Gobel Derek , Akpoghiran Fidelis , Murthy Ajith 
Published: October 2011

Abstract
Shell aspires to maximize unattended operations for all upstream E&P "green" and "brown" field assets using the appropriate level of automation. The benefits associated with down manned operations include the following:
Reducing staff exposure to travel hazards e.g., driving, sailing and flying Reduce staff exposure to process hazards at the well site and drill floor Increased production due to continuous monitoring and optimization by expert staff CAPEX saving due to elimination of unnecessary facilities such as process simplifications and reduced number of offshore beds OPEX savings due reduced travel and reduced logistics Increased staff productivity due to less time spent travelling Reduced GHG emissions as a consequence of reduced travel and improved process efficiency
The underlying premise is that the E&P process should as much as possible be monitored and controlled from a remote monitoring/control room staffed by the most experienced and capable people.
For "green field" facilities the basic design concept that we aspire to is unattended as the norm and attended as an exception that has to be clearly justified.
For "brown fields" we aspire towards as much as possible reducing attendance, again by monitoring and controlling from remote control centers.
This paper will describe the following:
Shell's overall remote operations strategy Technologies associated with remote operations, inclusive of production deferment reducing techniques such as data analytics and well/reservoir surveillance Shell guidelines associated with remote operations EP remote operations experiences in a number of different assets in Europe, USA and Africa
This paper demonstrates that, for Shell, remote operations is not a remote possibility, but is in the process of becoming a reality across our global upstream operations.
Acid-Fracture Conductivity Correlations for a Specific Limestone Based on Surface Characterization
Authors: Rodrigues Valdo F. , Campos Wellington , Medeiros Ana C. , Victor Rodolfo A. 
Published: October 2011

Abstract
Acid-fracture conductivity prediction is a key aspect in acid fracturing design and consequently in the oil and gas production forecast and economic evaluation. Acid-fracture conductivity correlations have been developed for some groups of calcareous rocks with a wide range of properties distribution. The experimental part of these studies has been based on samples from quarries and outcrops. This paper presents the development of conductivity correlations, which differs from previous studies by focusing on a specific oil producer limestone (Quissamã-ESP), by use of samples from well whole cores, and by performing comprehensive 3D surface characterization of the acid-etched fractures. Fractures were acid-etched in the lab with four types of acid systems at proper similarity conditions. The experimental study included core samples preparation, surface scanning with a laser profilometer, and rock strength and conductivity measurements. The 3D surface characterization not only supported the development of a conductivity correlation based on usual parameters, fracture width and rock embedment strength, but also enabled the development of correlations based on surface characterization parameters. It was also useful to manage experimental artifacts, to define the etching pattern, and to obtain more accurate fracture width calculation. The results showed that acid-etched fracture surfaces are rougher than usual engineering surfaces and present negative skewness, high kurtosis, and an intermediate isotropy - mostly random but with some spatial orientation. Four types of exponential acid-fracture conductivity correlations were developed for the Quissamã-ESP limestone, all them more accurate than the Nierode and Kruk correlation, adopted as a reference. The initial conductivity in the most accurate correlation is a function of a surface characterization parameter, while the rate of conductivity change with closure stress is a function of the rock embedment strength. The use of surface characterization parameters can improve the prediction of the initial conductivity, but not the rate of conductivity change with closure stress. Further studies will be necessary to improve the rate of conductivity change with closure stress prediction and to evaluate the possibility of structure creation, such as channels, in the acid-fractured surfaces.
Channel Fracturing in Horizontal Wellbores: the New Edge of Stimulation Techniques in the Eagle Ford Formation
Authors: Rhein T. , Loayza M. , Kirkham B. , Oussoltsev D. , Altman R. , Viswanathan A. , Peña A. , Indriati S. , Grant D. , Hanzik C. , Pittenger J. , Tabor L. , Makarychev-Mikhailov S. , Mikhaylov A. 
Published: October 2011

Abstract
The hydraulic channel fracturing technique relies on the engineered creation of a network of open channels within the proppant pack, which provides for highly conductive paths for the flow of fluids from the reservoir to the wellbore. These channels are created through a process that combines fit-for-purpose geo-mechanical modeling, surface equipment controls and fluid and fiber technologies. This paper reports the first implementation of the channel fracturing technique in horizontal wellbores.
A section of the Eagle Ford formation (TVD 10,900 - 11,500 ft) in the Hawkville field near Cotulla, Texas was selected for this study. This section comprises mainly limestone with 100 to 600 nD permeability and 7 to 10 % total porosity. The formation requires horizontal laterals with multi-stage hydraulic fracturing for economic production.
The channel fracturing technique was evaluated in twelve horizontal wells. Results from thirty eight offset wells treated with conventional techniques (slickwater or hybrid-type treatments) are also reported to compare performance. Non-normalized data from this sample of fifty wells showed hydrocarbon production increases ranging between 32% and 68% in favor of the channel fracturing technique.
The Hawkville field comprises a gas-rich section and a condensate-rich section. Reservoir simulations were performed on a sample of four wells located in the gas-rich section and two wells located in the condensate-rich section of the field to generate sets of normalized production data. These simulations accounted for variations in completion strategy, bottom hole flowing pressures and reservoir quality. Normalized production data for the sample of wells located in the gas-rich section of the field showed that the channel fracturing technique increased gas production by 51%. Normalized production data for the sample of wells located in the condensate-rich section of the field indicates increase in condensate production by 46%. Results from these history matches are consistent with the hypothesis that the channel fracturing technique enabled higher production by two concomitant mechanisms: increased area of contact with the reservoir and enhanced connectivity between the reservoir and the wellbore through highly conductive channels.
Positive features that were also observed during this campaign such as the elimination of near-wellbore screen-outs and significant reductions in proppant and water consumption are also summarized and discussed.