bluuebunny/crossref_metadata_2025_split huggingface dataset:
Carbonate Acidizing: Conjunction of Macro and Micro Scale Investigations
Authors: Fedorov K.M. , Smirnov A.S. , Kremleva T.A. 
Published: February 2011

Abstract
Acid treatment of carbonates is a common operation for production stimulation. A lot of codetergents for reaction rate decrease, for redistribution of acid placement in heterogeneous reservoirs and improvement of injection profile were proposed. These technologies are directed on stimulation improvement and are based on the mechanism of the carbonate acidizing which was investigated in the works [1, 2].
According to the investigated mechanism in some cases the flow and reaction of acid solution take place only in limited number of pore channels enormously increasing their radius and conductivity. This phenomenon was call wormhole formation. The existence of such channels raises well productivity significantly higher than in the case when acid flows through the whole porous media.
The research of Fogler and Fredd [2] resulted that wormhole formation depends on dimensionless Damkohler number. The general definition of Damkohler number is the ratio of reaction rate to the inflow rate to the reaction surface. So the value of the number depends on problem geometry. In the experiments on core plugs acidizing the formation of one channel occurs for number value 0.3 [3]. Increasing the Damkohler number (for instance by flow rate decrease) leads to the rise of the number of wormholes. The main trend is acidizing of all pores and front type chemical reaction with the whole carbonate consumption behind the front. In the inverse case (Damkohler number decrease) the sweep of pore channels by acid flow also rises but the asymptotical solution in this case is minimal impact of acid on rock (reaction rate is too small in compare with flow rate).
Permanent Optical Reservoir Monitoring System, A Possible Solution for Basement Fractured Granite
Authors: Wai Hou Tham , Kok Kheong Ong 
Published: February 2011

Abstract
In-well fiber optic monitoring systems are designed to provide continuous, high performance and high reliability data measurements in hostile environments. Today, optical sensing is a proven technology and is widely accepted by the industry after almost 20 years since its initial introduction. Adoption and deployment of this technology has increased dramatically over the last 10 years. The global footprint for this technology can be extended by applying the optical sensing systems to the challenging environment of basement fractured granite due to its uncertainty in temperature and pressure from the deep fractures.
Innovative Multi-Zone Water Injection: The Enfield ENC05 Story
Authors: Gibson Daniel , Medd Daniel , McCarthy Tom , Toldo Benni , Moselely Phil , Pudin Victor 
Published: February 2011

Abstract
The Enfield oil development, on Australia's Greater North-West Shelf, has now produced over 50 MMBBL oil. Enfield has been developed with both downdip and updip injection wells for pressure support and recovery.
An injector / producer pair were drilled in 2009 to develop the Enfield Sliver South area. For the project to be economically viable the wells needed to drain two fault compartments. In particular, water injection into each compartment needed to be proportional to the expected reserves. Recovery was expected at approximately 1.7 MMBBL from Segment 3 and 3.3 MMBBL from Segment 4.
Due to the location of subsea infrastructure a single water injection well needed to be drilled from the west with the first sands intersected in Segment 3, the smallest block, and then Segment 4 which required the most injection. One solution was to drill a dual lateral injection well. However, the cost and difficulty with injection control of this option was prohibitive for the project. A horizontal well design using two sets of stand alone screens, with Inflow Control Devices (ICD's), was selected to access both fault blocks. This provided both the flow control and the sand control required for these reservoirs.
This paper highlights the innovative ICD solution adopted to achieve the required proportional water injection and avoid over injection into Segment 3 (at the heel). Various models were constructed to analyse injection scenarios with variables including; sand penetration and quality, compartment volumes, near wellbore skins, producer off take rates, and pressures.
Upon drilling the well, and obtaining reservoir data, the final completion configuration was selected. This included the placement of three screens with 6 ICD ports open per screen for Segment 3 (at the heel of the well) and three screens with 32 ports open per screen in Segment 4 (at the toe of the well).
Both Matrix and Fracture injection have been observed in ENC05. The well is routinely exceeding 30,000 BWPD, at fracture rates through the ICD's, into both compartments and successfully supporting the over 20,000 BOPD oil producer to the north. This was the first time high rate proportional control, including fracturing, has ever been done with ICD's to our knowledge.
The Salym Project
Authors: Deacon Andrew , Mackay Howard 
Published: February 2011

Abstract
This text was first submitted to the 2009 International Petroleum Technology Conference in Doha, Qatar where it gained an award, placed third for Excellence in Project Integration.
Some doubted that a foreign company could do anything innovative to add value in Western Siberia. Yet, the story of Salym Petroleum Development demonstrates otherwise.
The Salym project shows how an oil company achieved fast-track development and rapid production growth. Not only were the Salym fields developed and produced at a breathtaking pace, but it was achieved in an environmentally and socially responsible way, benefiting the local community.
At project commencement the mandate was tough: design and build the entire oilfield including infrastructure, early oil production of 0.75 million barrels and start full scale production all within 26 months, in an unfamiliar, remote and challenging environment. Projects of this scope normally take four years.
Production has since exceeded 160,000 bpd, an unprecedented development rate in the heartland of the Russian oil industry. How? By combining Shell’s expertise and technologies with Russia’s vast regional experience to get the best results. Most importantly, SPD adopted the philosophy that success comes from enduring, positive relationships with employees, partners, contractors, shareholders, government authorities and members of the community – partnerships where everyone wins.
Integrated Analysis Combining Microseismic Mapping and Fiber-Optic Distributed Temperature Sensing (DTS)
Authors: Holley E. H. , Zimmer U. , Mayerhofer M. J. , Samson E. 
Published: February 2011

Abstract
Mapping the microseismic activity during a hydraulic treatment is widely used to determine the geometry of the stimulated fracture network. Microseismic maps provide reliable information on the development of fracture symmetry, half-length, azimuth, width and height, and their dependence on the treatment parameters and reservoir characteristics. Beyond that, these fracture geometries are used to better understand fracture modeling and even production characteristics.
Fiber-optic-based distributed temperature sensing (DTS) arrays provide almost immediate updates of the near-wellbore temperature distribution in approximately one-meter intervals. In injection treatments, the near-wellbore temperature distribution can be used to determine isolation effectiveness, the relative amount of fluid each perforation cluster takes, fracture initiation points, and effective fluid diversion. In production analysis, DTS measurements can quantify production rates from each perforation interval, crossflow rates while shut-in, and fluid types recovered from each perforation interval.
The detailed near-wellbore results available through DTS coupled with the far-field geometry acquired through microseismic mapping provide an accurate picture of the completion effectiveness. Microseismic mapping results often show adequate resolution over a large area but lack the fine resolution that would allow it to identify near-wellbore effects in the meter range. When modeling and interpreting the treatment geometry obtained by the microseismic-event distribution, it is important to include the correct near-wellbore effects, which are readily accessible through DTS measurements. Combining the two diagnostic tools is valuable for real-time decision making, post-treatment analysis, and production analysis to assess the completion effectiveness.
Incorrect assumptions about perforation breakdown, fracture-initiation points, interval isolation, or limited-entry effectiveness can lead to misinterpretations of the microseismic results. Using both diagnostic tools provides firm answers to the overall completion effectiveness. This paper focuses on three distinct aspects of combining the analysis of microseismic mapping and DTS. The first is the real-time aspect, wherein real-time decisions and adjustments are made during the fracture treatment with the objective of manipulating the results towards the desired outcome. The second is using both tools to perform more accurate postfracture analysis, including calibrated fracture modeling, entry effectiveness, correct interval spacing, and stimulated reservoir volume (SRV) analysis. The third area covered is combining these diagnostic tools with a production analysis, which is acquired through analysis of the temperature data.
A Conceptual Development of a Slim Drill Ship
Authors: Mortensen Asbjorn , Kah Keong Alex Tan , Geok Soon Ricky NG , Dimble Abhijit Dnyaneshwar , Vincent Sudhan , Ostvold Tom Waitz 
Published: February 2011

Abstract
This paper outlines a proposal for a slim drillship optimised for re-entry into existing subsea wells. The ship is designed to perform intervention operations using wireline and coil tubing equipment, through a high pressure riser string between the ship and the subsea wellhead, for access to the pressurised well. The slim drillship is also equipped with machinery and tools enabling it to drill new hole sections inside existing wells, for example long horizontal extensions, using slim jointed pipe that enters the well inside its production tubing. A key feature of a slim drillship is its high pressure (HP) riser, giving intervention tools access to the well containing hydrocarbons, eliminating the need to kill the well first with drilling mud. This feature does also enable the ship to use Manage Pressure Drilling (MPD) methods.
The drillship is initially designed for 7500 ft of water depth as well as well depth below the drill floor of 22500 ft. This is believed to be a practical depth limit for some known subsea fields in the North Sea area, Mexican Gulf, Brazilian shelf and areas offshore West Africa, and future areas in South Asia. It is possible to configure the ship for deeper wells.
This paper focus on the drill floor layout and open deck areas for storage of tubulars and equipment. An open mast for hoisting is proposed in order to enable a large drill floor for third party equipment. The mast is telescopic so the ship can lower the crown block and pass through the Straits of Bosporus and the Panama Canal, enabling the ship to move fast between arctic locations and tropical waters without passing south of South America. A novel vertical pipehandling method is used, with cylindrical rotating setbacks at a lower elevation than the drillfloor, and offline stand building on this lower deck. The use of an open mast layout as opposed to an enclosed derrick gives access to the well centre for intervention equipment, and enables rapid turnover between various tools going into the well.
Experimental Study of Solvent-Based Emulsion Injection to Enhance Heavy Oil Recovery in Alaska North Slope Area
Authors: Qiu Fangda , Mamora Daulat 
Published: February 2011

Abstract
This paper is the report for the second stage research of nano-particle and surfactant-stabilized solvent-based emulsion experimental study for the heavy oil in Alaska North Slope Area. The core flooding studies under laboratory conditions were implemented after the bench tests, which is including the phase behavior test, rheology studies and interfacial tension measurement. And these studies provide the optimum selecting method for the nano-emulsion which could be used in the core flooding.
The experiment results suggest this kind of emulsion flooding is a good optional EOR (enhanced oil recovery) process for heavy oil reservoirs in Alaska, Canada after primary production, where heavy oil lacks mobility under reservoir conditions and is not suitable for the application of the thermal recovery method because of environmental issues or technical problems.
Core flooding experiments were performed on cores with varied permeabilities. Comparisons between direct injection of nanoemulsion systems and nano-emulsion injections after water flooding were conducted. Oil recovery information is obtained by material balance calculation.
In this study, we try to combine the advantages of solvent, surfactant, and nano-particles together. As we know, pure miscible solvent used as an injection fluid in developing the heavy oil reservoir does have the desirable recovery feature, however it is not economical. The idea of nano-particle application in an EOR area has been recently raised by researchers who are interested in its feature-reaction catalysis-which could reduce in situ oil viscosity and generate emulsion without surfactant. Also, the nano-particle stabilized emulsions can long-distance drive oil in the reservoir, since the nano-particle size is 2-4 times smaller than the pore throat.
In conclusion, the nano-emulsion flooding can be an effective enhancement for an oil recovery method for a heavy oil reservoir which is technically sensitive to the thermal recovery method.
A Novel Nondamaging Friction Reducer: Development and Successful Slickwater Frac Applications
Authors: Sun H. , Stevens R. F. , Cutler J. L. , Wood B. , Wheeler R. S. , Qu Q. 
Published: February 2011

Abstract
Friction reducers are commonly used in slickwater fracturing operations to minimize energy loss due to tremendous amount of friction between tubular goods and water or brine solutions during the pumping of very high rate of fluids. Currently almost all friction reducers used are high molecular weight polyacrylamide emulsions. Large amount of polymers is injected into the formation even at very low concentrations (typically 0.5 − 2 gpt) due to the large volume of a typical slickwater frac treatment. Concerns have persistently been raised over possible fracture and formation damages caused by the friction reducers. All current friction reducers, including copolymers, are polymers with C-C backbones, which are difficult to break. Tests show that these polymers, even in the presence of oxidizer breakers, cause formation damage.
A novel friction reducer featuring easily breakable chemistry has been developed to offer clean, non-damaging slickwater stimulations. This new non-damaging friction reducer, delivered also in liquid form for the ease of transportation and field operation, is very effective as a friction reducer, compatible with common chemical additives (scale inhibitors, biocides, clay stabilizers, surfactants, brines, etc) and stable towards mechanical shearing. This paper will present the product development details and lab tests on the effectiveness of the new friction reducer in water and various brines and its hydration profile at different temperatures, chemical compatibility and breaking profiles. Formation damage studies on tight sandstone and shale formation on this new friction reducer in comparison with the conventional ones have been conducted and will be discussed in the paper. Results show the non-damaging friction reducer degrades easily with conventional breakers and leave no damage to the formation. Several successful multi-stage slickwater frac completions have been performed with the new friction reducer and these field trials will also be reviewed.
The Selection and Optimization of a Surfactant Package to Maximize Cleanup of a High-Density Fracturing Fluid
Authors: Cawiezel K E. , Singh A. K. , Carman P. S. , Cutler J. L. 
Published: February 2011

Abstract
In the Gulf of Mexico, momentum is increasing for drilling and completing wells deeper than 25,000 ft and with bottomhole pressures exceeding 20,000 psi. High-density base fluids have become standard components of fracturing or frac-pack completions to achieve working pressures below 15,000 psi at surface due to equipment limitation. Stimulation designs for these deep, high-profile wells aim to achieve long fracture lengths using large treatment volumes. Cleanup and maximum recovery of the high-density fracturing fluid is a necessity to maximize the effective fracture length, and thereby the production potential after these treatments.
Interfacial tension, contact angle and wettability are the key parameters to consider when choosing a surfactant package for maximizing fluid recovery. Historically, the surfactant packages that have been used in conventional fracturing fluids generally focused on water-wetting or non-wetting and lower surface tension results.
This paper presents details of laboratory studies to optimize a surfactant package for high-density base fluids. Fluid recovery studies were done on a sand column along with the measurement of the contact angle and interfacial tension of high-density base fluid with various surfactants. Core flow tests were also performed to evaluate regain permeability and cleanup. The tests with optimized surfactant package resulted in more than 90% regain permeability with a high-density fracturing fluid system and correspond with the results from the fluid recovery sand column testing. Laboratory tests show that the synergetic effects of interfacial tension, contact angle and wettability together are more significant than any one individual parameter and that more surfactant is not always better.
Selecting and optimizing a suitable and compatible surfactant package enhances the recovery and cleanup of a high-density fracturing fluid, which can result in highly conductive and longer effective fracture lengths.
The Special Successful PCP Applications in Heavy Oilfield
Authors: Wu Bingchang , Li Xin 
Published: February 2011

Abstract
Due to some particular advantages, such as the maximum suitable artificial lift system for heavy and sandy wells, higher pump efficiency and power saving, PCP (Progressive Cavity Pump) is becoming one of the popular oil artificial lift system in recent years. PCP artificial lift technology is up to 12% all over the world averagely, and 50% in Canada. For normal heavy oil (viscosity ≤1000CPo), the oil can be lifted to the surface only using conventional PCP system. But for the more viscosity oil (viscosity ≥1000CPo), the viscosity and frictional resistance in the formation and annular (between tube and sucker rod) will induce a very big difficulty for the oil flowing from the formation to pump depth and from pump depth to the surface, so some assistant measures must be used with PCP system to lift the oil from downhole to surface.
For SAGD (Steam Assisted Gravity Drainage), CSS (Cyclic Steam Stimulation) and SFD (Steam Flooding Drive) wells, steamed gas is assisted to decrease the oil viscosity to enhance its fluidity. PCM Vulcain™ (PCP with metal stator and metal rotor) had been successfully applied in such kind of wells since 2007. And PCM PCP with 198 high temperature resistant elastomer had been successfully used in 4 CSS wells. In addition, several high viscosity wells are producing with normal PCM PCPs assisted with light oil mixing system, hot water injecting system and electricity heating system.
This paper will discuss the successful PCP artificial lift system applications with above 5 special assistant systems. This paper will be a guider for such kinds of special PCP technologies to be spread and applied widely in the world.
Downhole Electrical Heating System: Feasibility of Heavy Oil Implementation in Offshore Congo
Authors: Vielma W. E. , Congo Eni , Misenta M. E. , Ponticiello I. , Secco G. 
Published: February 2011

Abstract
The heavy oil reservoirs exploitation is one of the future targets of the major oil companies worldwide. Most of the heavy oil fields are produced through cold production methods leaving therefore significant amounts of unproduced reserves. To date different EOR techniques (like for instance steam injection or other thermal methods) are available to achieve higher recovery factors.
However, some technologies, like the downhole electrical heating have been recently improved, allowing cold production enhancement therefore maximizing the recovery factor without incurring on the high investments associated to the implementation of EOR. In order to increase the production of the heavy oil reservoir in the offshore Congo, a study of down hole electrical heating application has been carried out showing encouraging results.
The aim of the study was to evaluate the benefit associated with the application of this technology through the reservoir modeling. Significant results were achieved in terms of recovery factor increase.
The use of heat to increase the reservoir temperature showed good results in terms of heavy oil viscosity reduction starting from 1,000 cP at reservoir conditions (34°C) down to much lower values throughout the production time resulting in increased production rate and consequently, higher recovery factor from this reservoir.
The first application of this technology is foreseen in a long horizontal well section of about 600 meters length completed with production sand screen. The electrical heating mineral insulated three phase cables will be deployed throughout the horizontal well section by means of a dedicated completion tail pipe.
Several design challenges have been faced to properly centralize the heating cables and clamp the same around the completion tail pipe due to the well size constraints.