bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of a High Boost, High Power, Ultra-deep Twin Screw Multiphase Pump System
Authors: Williams Adrian , Urban Bob , Margulis Jonah 
Published: February 2011

Abstract
Between 2005 and 2010 Shell has been working with Flowserve and other specialty contractors to develop a next generation pumping system requiring a complete review and redesign of all major components. The work has been performed at multiple locations in Europe and the Americas by an integrated team. It has now reached the level of maturity that it can be shared within the industry. In 2004, Shell performed a comprehensive assessment of industry capability for subsea pumping. This study concluded that boost pressures available at the time were insufficient to meet future project needs, particularly for ultra-deep, heavy oil applications with large gas volumes. As a result the high boost, high power, ultra-deep twin screw multiphase pump development was initiated.
The development included building and testing the subsea twin screw pump, a submersible motor, subsea electrical high power connectors, a pressure compensation system and high bandwidth fiber optic health monitoring system in addition to a purpose-built high capacity test loop. The project is now reaching its conclusion with integration of the core components due to take place by the end of 2010. Individual components such as the pump have already been tested up to 4 MW shaft power, 2400 psi differential pressure, flow rates up to 90,000 barrels per day, with viscosities ranging from 2 – 2,000 centipoise, an order of magnitude greater than any similar existing machine.
This paper describes the work performed, the major challenges addressed and the methodology used to overcome them. One particular challenge was the implementation of rigorous HSE requirements for such high energy, heavy equipment.
Gas Well Deliquification Using Microwave Heating
Authors: Kamal Mohamed , Nikhil Ghodke , Patwardhan S. D. , Al-Dogail Fuad 
Published: February 2011

Abstract
One of the challenging problems of gas production is the liquid loading of a gas well. It is the inability of the produced gas to remove the produced liquids from the well bore. This phenomenon has a significantly negative impact on gas well production rate and reservoir pressure due to build up of liquids in the well bore. The accumulated liquid may be in the form of formation water, condensed water or hydrocarbons condensate which acts as a hindrance to the formation gas getting produced. The ultimate recovery of gas is dependent on the economic removal of accumulated liquids, to allow the gas to get produced. This paper discusses a new idea of using dielectric heating using microwaves to heat and vaporize the water and hydrocarbons in the wellbore, if present. As a result of this heating, the fluid density decreases and the gas and vapours flow naturally to the surface. The frequency of microwaves in general is 2450 MHz; depending on the need, the frequency can be varied. Experiments were carried out on the use of this technology and the results are encouraging. This paper discusses this new technique, results obtained from conducted experiments, and provides advantages to the current methods.
Understanding Wormholes in Carbonates: Unprecedented Experimental Scale and 3-D Visualization
Authors: McDuff Darren R. , Shuchart Chris E. , Jackson Shalawn K. , Postl Dieter , Brown James S. 
Published: February 2011

Abstract
The combination of matrix acidizing experiments with visualization techniques is commonly used to elucidate the details of wormhole networks formed during matrix acidizing of carbonate reservoir rock. Previous experimental studies of wormhole growth have focused mainly on small linear core plugs, with only a limited number of radial flow studies published in the literature. Results from these conventional experiments have provided extensive information on linear wormhole growth in one dimension (1-D) along with some basic insights into radial growth mechanisms in 2-D. However, larger-scale test systems must be considered if 3-D wormhole characteristics are to be understood. Toward that end, a new methodology has been developed which integrates (1) acidizing experiments on carbonate rock samples up to 14 ft3 in volume, (2) high-resolution nondestructive imaging and analysis, and (3) computational modeling to extend the results of experiments to field applications. This article highlights the experimental and imaging components of the methodology.
Managing the Blackstone Swanhills Sour Gas Reservoir Pool, Western Canada
Authors: Chen Andrew , Lamb Derek , Deyell Nicole , Higgins Carl 
Published: February 2011

Abstract
The Blackstone Beaverhill Lake (Swanhills member) "A" Pool is a dry gas reservoir of the sour content up to 22% of H2S+CO2, one of a series of highly dolomitized late Devonian aged reef carbonate structures in the Western Canada. Discovered in 1979, the Blackstone pool is trapped at a depth of 4800 m TVD with a gas column height of 165 m and with an underlying aquifer. The pool size was initially estimated at 1,150 bcf from the early appraisals and the 1985-2000 production data, but revised due to the impact of water influx with two high rate producers watering out at high loading rates. Depleted by only six wells, the pool has produced 770 bcf of gas as of Dec 2009. The final EUR recovery factor could eventually reach 93% under optimized favorable conditions.
Although the pool behaves like a single tank with an average permeability of 50 md, the complexity of dolomitized reef facies, barriers and baffles, porosity and permeability features, made it difficult to forecast the production performance and execute infill drilling plans, on the basis of integrated geoscience & reservoir engineering studies. Additional uncertainties, such as high drilling/workover cost and risks, facilities and gas gathering & processing, gas prices, also confront the pool's depletion plan.
By providing a detailed field case study of the Blackstone pool, this paper demonstrates that reservoir management is a reciprocating business process between fact findings & business options constrained by cost effective measures and commercial matrixes. Timing often emerges as a critical factor. The ultimate goal is to protect and maximize the value of assets. The Blackstone pool proved to be one of a few successful high RF water-drive carbonate reservoirs. Simple water chemistry tracking turned out to be a very effective surveillance practice that altered the reservoir management plans.
Development of a New Completion Fluid Using Polyglycolic Acid Powder
Authors: Nakai Takayuki , Daitoh Masaki , Morita Nobuo 
Published: February 2011

Abstract
Polyglycolic Acid (PGA) has been widely used as a string to stitch scars during medical operations. The string left in human body dissolves with time. It is harmless and biodegradable. Although these properties are attractive, the high cost prevents for oil field applications. However, a technology has been developed to produce tons of PGA with a low cost.
Granular CaCO3 has been used as a fluid loss control material for completion fluids. The mud cake has to be removed after completion instruments are installed, but tends to remain partially undissolved. The PGA powder turns to be a liquid acid with time if it is mixed in water. It is also environmentally harmless if it is disposed in ocean. It is judged that these properties may be suitable to replace the granular CaCO3.
The experiments consist of viscosity, fluid loss, and cake thickness measurements varying temperature and particle size distribution by using PGA powder as a fluid loss control material in a Xanthan Gum polymer completion fluid. Particle size distribution is optimized to minimize fluid loss. Then, the particle size change with time is measured. The mud cake consisting of PGA powder completely disappears after several days.
The results show that the amount of fluid loss tends to decrease when the particle size is finer. Similarly, the thickness of the mud cake is significantly affected by the particle size distribution of PGA powder. It is proved that the PGA completion fluid has better mud properties compared with commercially available low solid polymer fluids. The advantage of the PGA powder as a fluid loss control material is (A) no permeability loss since it disappears with time in pores, (B) a low fluid loss since particle distribution is optimized to minimize fluid loss, (C) no acidizing is required after use since it dissolves itself due to hydrolysis, and (D) it is environmentally harmless.
Estimating Permeability Distributions From Pressure Pulse Testing
Authors: Ahn Sanghui , Horne Roland N. 
Published: February 2011

Abstract
This work investigated how to utilize multiple frequency components of data from pressure pulse tests to estimate the interwell permeability distribution in an equivalent multicomposite reservoir system. When given pressure time series data in the active well and the observation well, the method of attenuation and phase shift characterizes the reservoir properties without having to know the flow rate. Synthetic homogeneous and heterogeneous reservoir cases were examined under periodic steady-state conditions with multiple sinusoidal inputs and multiple frequencies contained in a square pulse signal. By matching attenuation and phase shift at various harmonic frequencies, the results were found to be in good agreement with the actual permeability distribution trend. The analysis of multiple frequencies is useful in describing the heterogeneity of the reservoir parameters quantitatively, when the radius of cyclic influence is consistent with the sourced frequencies.
A new inverse framework of obtaining the permeability distribution by utilizing frequency contents was developed. Attenuation and phase shift of specific frequencies provide the key to describing the reservoir characteristics, and when conditioned on those parameters, the degree of heterogeneity in the reservoir can be revealed. Attenuation and phase shift provide an ‘indicator characteristic’ which can reveal reservoir heterogeneity – without using history matching of pressure, which can be sensitive to noise.
Estimation of Fracture Effective Permeability by Upscaling Using Ensemble Kalman Filter and Streamline Simulation
Authors: Tanaka M. , Tanaka S. , Arihara N. , Okabe H. 
Published: February 2011

Abstract
As naturally fractured reservoirs (NFRs) present a wide range of geological characteristics and complex flow mechanisms between fracture and matrix, reservoir simulation is highly necessary to properly evaluate reservoir performance. Modeling and simulation of NFRs are conducted commonly with two alternative approaches, the dual-porosity model and the discrete fracture model. The single-continuum approach, where fracture systems are represented by effective permeability, is often more effective and flexible for NFRs simulation.
In this paper, we present an upscaling approach to estimate the effective permeability for NFRs based on flow calculations. We used the local-global upscaling (LGU) method as the first step to calculate effective permeability for the discrete fracture model. As the second step, the ensemble Kalman filter (EnKF) approach was applied to assimilate an ensemble of the upscaled models to the production history from the reference model. Although the EnKF has been successfully applied in recent years to inversion problems for inferring parameters from the core scale to the reservoir scale, it is difficult to estimate channel-like high permeability parts because the EnKF works well under the assumption of the Gaussian distribution. We demonstrate and confirm accomplishments and limitations of the LGU and EnKF applied to the discrete fracture model. In order to overcome the limitation, we refined the effective permeability distribution with the velocity field that is calculated by a streamline model.
We demonstrate two cases describing different types of NFRs for which we could obtain satisfactory upscaling and inversion results. In each case, a reference model was set up initially with a fine grid explicitly including discrete random fractures, and 40 realizations were constructed, upscaled to a coarse grid, and processed by the EnKF. The effective permeability fields updated by the EnKF could match the production history, but the streamline and water saturation distributions did not resemble the those of the reference model. The velocity fields that were obtained from the reference model could refine the upscaled models with and without the EnKF assimilation. For all flow simulation, we used our streamline-based simulation model.
A New Look at Low-Resistivity and Low-Contrast (LRLC) Pay in Clastic Reservoirs
Authors: Claverie Michel , Allen David F. , Heaton Nick , Bordakov Georgiy 
Published: February 2011

Abstract
LRLC reservoirs are increasingly at the forefront of the industry's concern in diverse projects ranging from offshore deep-water exploration of turbidites to the development of brown-field secondary objectives. Although LRLC reservoirs have been under production for many years, their identification and the calculation of their reserves and flow properties remains a difficult challenge. This paper compares different petrophysical workflows for clastic reservoirs where thin conductive laminations and high bound water fraction are the source of low resistivity and contrast, with a view to reducing uncertainty in saturations and improving producibility prediction.
When thinly laminated reservoir layers are intercalated with conductive non-reservoir layers, the apparent formation resistivity is dramatically reduced and the apparent clay volume is increased, and the hydrocarbon volume and the permeability calculated from conventional petrophysics are underestimated. We describe new developments in laminated sand analysis and the practical implementation of resistivity anisotropy, including corrections for clay intrinsic anisotropy and thin non-reservoir resistive layers.
Reservoirs with fine grain material, grain-coating clays, or dispersed clays may display high bound water volumes, yet possess significant quantities of producible hydrocarbon. While conventional petrophysical analysis can provide reliable water saturation, it does not distinguish clay- and capillary- bound water from free water. Also, shaly and silty reservoirs often present a complex mineralogy which makes estimates of clay volume and grain density uncertain. We describe the application of nuclear spectroscopy and NMR logs to calculate clay volume, porosity and bound water volume and illustrate their impact on the quality of the resulting evaluation.
Although the petrophysical methods presented were developed for thinly bedded reservoirs, we show that they can improve the analysis of both LRLC and conventional clastic reservoirs. In particular, we propose fit-for-purpose workflows that reduce the uncertainty of fluid volumes and rock flow properties.
Kashagan Field: Defining Stimulation Methodology, Implementation, and Results Evaluation To Provide a Program Redesigning Criterion
Authors: Foglio G. , Wtorek S. 
Published: February 2011

Abstract
The Kashagan oil field, located in the North Caspian Sea in the Republic of Kazakhstan, is believed to be the largest oil discovery in the past thirty years.
To unlock the field's full potential, in particular of the inner non-karstified region, most of the wells have been stimulated with 15% hydrochloric acid, pumped through-tubing in the earlier jobs while coiled tubing units have been later introduced as part of an optimization process.
Almost all initial stimulations have been assessed by well tests accompanied with production logging enabling to carry out a comprehensive analysis of the treatments.
It is known that, significantly larger portion of recoverable oil lies in the tighter non-karstified inner region and therefore an optimized and a successful stimulation practice is essential to an economic project success.
Furthermore, to achieve reservoir engineering stimulation objective of an average -3 skin along the selected perforated Unit 1 intervals, Fig1, it was recognized necessary to review all possible stimulation techniques and acid conveyance methods to maximize the chances to achieve such a challenging an objective.
This paper outlines, in a task and result step format process, an approach that was utilized to select the best stimulation methodology for all Kashagan geological facies and recommendations to formulate a stimulation technique which overcomes technical problem encountered during field operations. Examples are also included to show the results of base original and redesigning criteria.
A 5-Year Survey of Applications and Results of Placing Solid Chemical Inhibitors in the Formation via Hydraulic Fracturing
Authors: Gupta D. V. , Brown J. Mike , Szymczak Steve 
Published: February 2011

Abstract
Solid chemical inhibitors placed in the formation during hydraulic fracturing have provided inhibition protection for up to five years. Deepwater operators, especially, desire longer inhibition periods. This paper provides a summary on treatment results over five years and over 1500 wells. It covers inhibition for scale, paraffin and asphaltene either as a single application or as a multiple product application. These applications have been in various formations including deepwater, tight gas and coal bed methane formations. The longest documented treatment has been in the ground for over five years.
Placing a solid chemical inhibitor into the formation via the fracturing process requires a product that is compatible with the fracturing fluid, does not adversely affect conductivity and provides long term inhibition through the controlled release of the inhibitor into the produced fluid. The solid inhibitor is added to the fracturing proppant. Primarily this is a mass-balance process by which a finite amount of inhibitor desorbs over time. The goal is to maximize the inhibitor loading, minimize the chemical release rate without negatively impacting the stimulation.
In the treated wells inorganic and organic deposition has been arrested for extended periods when compared to alternative liquid addition applications. Solid scale inhibitors have been the most common treatment and are monitored through residual analysis. The paraffin and asphaltene inhibitors are monitored through comparative testing. The paper details both the time and the cumulative production that has flowed through the respective proppant packs.
Wells that are scheduled for hydraulic fracturing and that display tendencies for organic and/or inorganic deposition are candidates for solid chemical placement during the fracture. The results from over 1500 wells indicate that this method for deposition inhibition reduces intervention costs and lowers lifting costs.
Resolving a Water Shortcut Between Old Wells with Multiple Completion Zones: Example in the Dan Field
Authors: Eriksen Katrine , Hansen Ove Egstrøm , Van Der Post Niko 
Published: February 2011

Abstract
In mature fields an important challenge is shutting off injection water breakthroughs. In the Dan field offshore Denmark developed with multi-zone completed long horizontal wells, the primary method now is closing Sliding Side Doors (SSDs) in the horizontal completions. A shortcoming of this method is that it does not work if there is communication between individual zones or holes in the tubing. This is the case in many of the up to 20-year-old wells.
The primary goal of a recent coil tubing conveyed well intervention was to remove a shortcut between two horizontal wells: a producer with 16 sand fracced zones and an injector with 5 water fracced zones. This was planned to be done by closing one or two PSI zones in the injector. The connection could not be removed by shifting zones in the producer due to a restriction in the vertical section, making the horizontal completion of the well inaccessible.
Production logging results of the shut in injector showed a substantial cross-flow from zones 1 and 4 into zone 3 via both the sliding side door and a hole in the zone. Due to the presence of cross-flow, the injection well was effectively injecting an estimated 4,000 bbl/d into the culprit zone, when closed in at surface. Due to the tubing leak in zone 3 it was not possible to stop the flow out of the zone by shutting the door, so all zones (1-5) in the well were closed, and injection was stopped. The closure of all zones in the injection well resulted in an immediate response in the production well, reducing water production with 6,000 stb/d while increasing the oil production with 1,200 stb/d.
The intervention and responses in nearby wells indicated that the injection well was connected to up to three other water injection wells and up to two other production wells. In this paper the reasons for these short cuts and the impact it has on water flooding are analysed.
The lack of water injection in the area has resulted in declined production in other wells, hence the future challenge for the area is finding a new way of shutting the connections either by means of chemical conformance treatment in cases of connected zones or straddles in wells with tubing holes.
How to Decide Between Horizontal Transverse, Horizontal Longitudinal and Vertical Fractured Completion
Authors: Economides M. J. , Martin A. N. 
Published: February 2011

Abstract
Augmented by the recent activities in shale gas, hydraulic fracturing of horizontal wells has become increasingly popular, although the technology has existed for over 20 years. The success in shale gas activities and advances in completion technology may have generated the false impression that fractured horizontal wells may be successfully applied to almost any formation.
Although the very low-permeability shale gas formations in the cost-controlled environment of North America may have justifiably made multiple-fractured horizontal wells the completion of choice, many do not realize that there are circumstances where a simple vertical fractured well may significantly outperform a fractured horizontal well. Because it is usually too late to change completion type once the wellbore has been drilled, it is vital that the selection of type of fractured completion to be used is considered during initial well and field development planning.
This paper will discuss the production mechanisms from horizontal transverse, horizontal longitudinal and vertical fractured wellbores. Calculations of the incremental performance of each configuration are done for both oil and gas wells. There are physical and economic limits and criteria. For example, for gas wells in reservoirs above 0.5 md, there is an unacceptable reduction in the performance of each transverse fracture because of enhanced turbulence effects. There are also economic criteria for selecting which type of completion is the optimum choice. We look at a range of reservoir and proppant pack permeabilities and discuss the optimization of fracture geometry. The paper not only delineates areas of indicated application of each well completion but it highlights the importance of considering the hydraulic fracturing process from the very start of wellbore planning. The processes involved in planning a wellbore for efficient decision making and maximum flexibility of choice are also described.