bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Coiled Tubing Extended Reach Practices in the Bakken Region: A Case Study
Authors: Griffin John , Nichols Chris 
Published: October 2012

Abstract
Wells in the Bakken formation of the Williston Basin are currently being drilled in excess of 20,000 ft. measured depth with horizontal sections often exceeding 10,000 ft. in length. Due to current coiled tubing (CT) operational limitations, such as premature lockup, multiple zones at the toe are often left stimulated but possibly flow restricted due to unmilled frac plugs or ball seats. Technological advancements in friction reducers, downhole tools, and string design have greatly improved the industry's methods of decreasing mechanical drag, enabling coiled tubing to reach greater depths. With current pre-job modeling software, expected depths can be simulated but, due to lack of knowledge regarding technical operating parameters, results are inconsistent with field data, leaving operators unsure as to whether zones will be left behind.
This case study was conducted as a sensitivity analysis to provide operators and service companies with a means to measure the effectiveness of current extended reach practices and tools.
A field trial case history for a number of similar wells was performed comparing differences in actual versus predicted modeling of surface weights and maximum depth before reaching lockup. Preliminary results show average gains of 10% in extended reach with the use of downhole water hammer tools (WHT) and frictional drag reducers. A 50% reduction in circulating pressure has been obtained, extending coiled tubing fatigue life. Additionally measuring lubricity in the flowback fluids at surface provides an indication of fluid performance.
This case study, which is based on field results and empirical analysis of over 40 wells, outlines a method to more accurately forecast CT lockup depths when running WHT or pumping friction reducers. This is enabled through greater understanding of the WHT or friction reducer that is being applied. From this study, operators and/or service companies can develop operating guidelines to help achieve maximum milling efficiency based on technical information provided.
A Distributed Microchip System for Subsurface Measurement
Authors: Yu Mengjiao , He Sufeng , Chen Yuanhang , Takach Nicholas , LoPresti Peter , Zhou Shaohua , Al-Khanferi Nasser 
Published: October 2012

Abstract
A revolutionary cost-effective "Microchip" system capable of measuring temperature and pressure over the entire wellbore was developed and tested in the field. The Microchip system includes two major components: the surface devices and the "tracer." A tracer (~7.5 mm in diameter) consists of fiber optic sensors, a SoC IC (System-on-Chip, which includes microcontroller, memory, transmitter and receiver circuits) and a battery, all encapsulated in a protective chemical coating shell. The surface devices include an "initiator" to reset the circuit of the tracer and a "data collector" to retrieve data from the tracer using wireless communication. When used in the field, tracers will be injected together with the drilling fluid. As the tracer travels through the wellbore, it will measure the temperature and pressure through the entire wellbore and store the data in the on-chip memory. When the tracers are carried out of the borehole by the drilling fluid, a "data collector" will communicate with the tracer to download the data stored in the on-chip memory on the tracer. Thirteen tracers were injected in an 11,050ft well and circulated with a 13ppg mud at 400-500gpm. After travelling about 6.6km in the 8-3/8 inch wellbore to a depth of 11,050 ft, seven tracers returned to the surface successfully. The first tracer returned to the surface after 57 min. Data recorded on the tracer shows a bottom hole pressure of ~7500psi and flowing bottom hole temperature of ~190 degrees Fahrenheit. Results are consistent with the static bottom hole pressure and temperature. The Microchip system can be used for subsurface measurement or as a diagnostic tool for identifying problematic zones. As an open platform, the Microchip system could also be expanded to other measurements by using different types of sensors. This Microchip system can be used in drilling and completion, pipeline monitoring and many other applications.
Removal of Sand Control Screens and Bottom Hole Assembly in Cased Hole Gravel Packed Wells in Chad, Africa
Authors: Nandogongar Alladoum , Soulanoudjingar Stephane D. , Driver Delbert , Mayfield Gary , Kamps Jake , Jimenez Manuel , Anderson Robin 
Published: October 2012

Abstract
The fields operated by Esso Exploration and Production Chad Inc. (EEPCI) in a consortium project with PETRONAS and Chevron in Central Africa, target highly unconsolidated sandstone formations. Sand control equipment must be utilized to prevent production of sand resulting in failure of downhole and surface equipment. Screens can erode as a result of "hot spots" where fluid velocities have increased considerably, allowing sand entry into the wellbore causing the subsurface equipment to fail and decrease production. With high drilling costs, and the limited amount of surface space, it has become critical to repair the more prolific of these damaged wells.
This paper provides an overview of the development and utilization of various failed sand control equipment removal and replacement techniques for workovers. Screen removal poses challenges not typically encountered when pulling other bottom hole assemblies from the well. The team has utilized existing available equipment and modified tools to address these unique challenges during workover operations.
Initial attempts to pull sand control equipment required weeks of rig time and met with limited success. Packer release tools were not always effective, and milling over these packers proved problematic. Additionally, long screen sections were difficult to pull. Learnings from each workover operation were incorporated until the optimum methods were eventually identified. Also, tools were modified resulting in time and cost efficiencies.
Additionally, a systematic approach of selecting the best candidates for repair was developed, taking into account various wellbore complexities such as age, type of completion, length of the bottom hole assembly, among others. Each complexity is weighted based on previous pulling experiences as well as taking into consideration the total volume of oil to return to production.
Since June 2009, 15 gravel pack failures were repaired, and wells returned to production utilizing these evolving and improving techniques. This represents over 5,300' of pulled screens. The first successful repair (June, 2009) required 20 days to complete. Applying learnings and improved techniques, the average repair time has decreased to 9.5 days (one at 6 days), with an average 40% of cost reduction; 60% to 70% less than the cost of a new drillwell.
A New Approach to Deliver Highly Concentrated Surfactants for Chemical Enhanced Oil Recovery
Authors: Barnes Julian , Dirkzwager Henk , Dubey Sheila , Reznik Carmen 
Published: October 2012

Abstract
A novel process has been developed to produce highly concentrated forms of surfactants suitable for chemical Enhanced Oil Recovery (cEOR) in the form of powders. Powders are advantageous for cEOR applications because, through their lower water content (typically 3%), they have the potential to reduce transportation costs and simplify the logistics of transporting surfactants from the production location to field locations.
Data are presented showing the properties and advantages of powder cEOR surfactants and how they compare to the more conventional liquid form of surfactants. The manufacturing route first involves the preparation of higher active matter liquids (around 70% active) that are subsequently converted into powders using dedicated, standard mixing equipment, the same type used for the manufacture of laundry powders. In this work, several surfactant powders were produced on a pilot plant scale using a number of internal olefin sulfonates to establish applicability for different cEOR projects. The blended powders are agglomerates of surfactant and sodium carbonate and were made both with and without polymer (termed ASP and AS powders respectively). The AS and ASP powders were found to easily dissolve in brine, eliminating the need for special field equipment for dissolution, and gave faster polymer dissolution in water compared with dissolving the polymer as a separate component. The powders have acceptable physical properties that facilitate transport and dispersion in brine and have been tested at desired ratios of surfactant to alkali.
This paper also outlines how higher active matter liquids can be manufactured to avoid gel phases, improve their handleability and lower their viscosity.
The surfactant powder approach has the potential to substantially reduce costs for full scale chemical EOR projects where large chemical volumes are manufactured, transported, stored and injected.
Improving Well Placement and Reservoir Characterization with Deep Directional Resistivity Measurements
Authors: Constable Monica V. , Antonsen Frank , Olsen Per Atle , Myhr Gjøril M. , Nygård Atle , Krogh Morten , Spotkaeff Matthew , Mirto Ettore , Dupuis Christophe , Viandante Mauro 
Published: October 2012

Abstract
The last decade has shown a significant development in resistivity measurement technology providing directional resistivity at a larger scale than conventional logging tools. The latest development can identify resistivity contrasts ten's of meters around the wellbore.
Statoil has tested deep look-around resistivity on a range of fields during the last 2 years and recorded data in more than 10 wells on the Norwegian Continental Shelf. The look-around images provides information at a scale that bridges the gap between conventional logging and seismic and adds important new pieces to the reservoir characterization puzzle. In good reservoir conditions, resistivity contrast up to 30 m away from the well-bore has been observed.
This study will focus on results from the Visund and Åsgard fields, and will demonstrate how the device was used in a range of different applications in the geosteering operation:
Detection of the reservoir boundary up to 20m TVD away. Detection of oil bearing reservoir from within underlying shale, through a water zone. Detection of Gas-Oil Contact (GOC). Detection of Oil-Water Contact (OWC) up to 20m TVD away. Detect faulting of the reservoir.
These examples will highlight why deep look-around resistivity is a step change related to the possibility for doing pro-active well placement of highly deviated wellbores as well as for gaining a larger reservoir understanding. The imaged variation in resistivity contrasts can be related to geologic zonation and fluid content on the reservoir scale, which opens up a much better cross-disciplinary communication between geophysicists, geologists, petrophysicists and reservoir engineers. Finally, the deep resistivity images contribute in optimization of completion solutions when incorporating information on the reservoir scale.
World First Riserless Light Well Intervention (RLWI) Technique to Mill and Clean Hard-Packed Debris, and Then Pull a Bridge Plug From a Live Subsea Well Using Electric Wireline
Authors: Delot Quentin , Eikeland Tommy , Gundersen Svein Helge , Skeie Normann 
Published: October 2012

Abstract
A subsea production well in the North Sea was being serviced with a riserless intervention which inadvertently resulted in fill atop a temporary bridge plug. Riserless slickline and traditional e-line attempts to remove the debris and pull the plug were unsuccessful. A rig or intervention vessel with riser for coiled tubing cleanout was unavailable for approximately a year. The operator requested innovative solutions and selected a unique riserless light well intervention consisting of an e-line cleaning tool with a reverse circulating bit and bailer sections to break through the hard-packed debris, vacuum it into the bailers, and retrieve it to surface. The remaining debris in the internal fishing neck of the plug was sucked up by a high-powered e-line cleaning tool and the plug was pulled in the same run. The job was executed without incident from a small, dynamically positioned, vessel with a moon pool and a subsea lubricator, saving the operator about one year's deferred production versus waiting for the coiled tubing solution. This paper discusses the operation of the downhole tools and procedure for riserless deployment to achieve the objectives and create this value.
Successful Application of Venturi Orifice Gas Lift Valve in Kaji-Semoga Field, South Sumatra: A Case Study
Authors: Rilian Nova Arthur , Rohman Adam Fatchur , Hamzah Kamal , Arseto Yoseph Itok , Narso Narso , Kurniawan Candra 
Published: October 2012

Abstract
Continuous gas lift system is currently widely used as artificial lift in Kaji-Semoga Field, in fact at about 46% of total producing wells. The average depth of gas lift wells in Kaji-Semoga is 3,200 ft, utilizing 2 to 5 conventional gas lift valves in a single production string. Common problems experienced when optimizing gas lift wells in Kaji Semoga field are instability of flow due to fluctuation of gas lift injection rate and pressure, limited gas injection volumetric rate, and limited compressor discharge pressure that leads to limited casing head pressure at well head, especially for remote wells with high tubing pressure at injection point.
A new injection valve type, venturi orifice gas lift valve with breaking-out gas device, has been studied and proposed as a solution to the aforementioned problems. This type of valve has been installed as gas lift injection valve at some pilot wells by using slick-line unit. The aim of venturi orifice is to reduce pressure difference between casing (upstream) and tubing (downstream) at injection point and to deliver a greater amount of gas lift injection at the same casing head pressure (compared to traditional orifice valve). Meanwhile, the aim of the breaking-out gas device is to break the injected gas into very small bubbles and homogenize with the liquid so that flow stability can be achieved.
Selected candidates for pilot wells are the ones with high productivity index (PI), high flowing pressure gradient (above 0.18 psi/ft) and limited gas lift manifold pressure. Well modeling and simulation have been conducted for these selected wells using production optimization software to predict gas lift well performance after installation of new injection valve, whereupon the simulation result is matched with actual data.
Applying venturi orifice gas lift valve has produced successful results: the liquid rate of the pilot wells has increased by about 40%, with 30% gas injection rate increment under the same conditions. Computer simulation also provided similar results to the actual well performance and met expectations. The pay-out time (POT) of this project was less than 2 days.
Experimental and Computational Investigations of Viscous Fingering at High Mobility Contrasts
Authors: Dawson M. A. , Yale D. P. , Kushnick A. P. 
Published: October 2012

Abstract
Viscous fingering arising from adverse mobility contrasts is encountered in numerous oil recovery processes and may present challenges to efficient operation. As the mobility contrast between fluids increases, these challenges, such as bypassed oil, become more severe. This paper examines the phenomenon of viscous fingering at high mobility contrast from both an experimental and a modeling perspective. The experimental studies are carried out in a state-of-the-art apparatus, which simulates realistic subsurface conditions. The apparatus is designed to accurately capture the effects of geomechanics at reservoir conditions in a 3D chamber that is over two meters in diameter, enabling examination of the viscous fingering under previously untested conditions. The results of a high mobility contrast experiment with mobility contrast of approximately 25,000 are presented. A simulation of the experiment is also provided. The simulation demonstrates the potential to sufficiently model this complex phenomenon even at high mobility contrast. As enhanced oil recovery methods become more pervasive, understanding and modeling viscous fingering under realistic reservoir conditions is becoming an increasingly important area of research, and the experimental and computational investigations presented herein provide new insight into this complex phenomenon.
A Study on the Remaining Oil After Strong Base ASP flooding
Authors: Zuo Xiwen , Li shiyong , Li Weiyan , Song Rue , Wang Tongwei , Xu He 
Published: October 2012

Abstract
ASP flooding tests in Daqing oilfield show that it can greatly enhance oil recovery and provide a powerful technical support for sustainable development of the oilfield.At present, ASP flooding in Daqing oil field has entered commercial popularization stage and the supporting technologies such as reservoir engineering, production engineering, surface engineering involved with multi-disciplinary, chemical agent quality inspection and field injection have been formed.However, there still lacks in-depth recognition about reservoir developing conditions and remaining oil distribution after alkali ASP flooding. Therefore, on the basis of analysis of dynamic and static data, application data from newly drilled wells and coring data before and after ASP flooding, this paper gives a clear understanding of the reservoir developing condition and oil displacement effect and confirms remaining oil distribution characteristics and its forming causes from macroscopic to microcosmic perspectives and from horizontal to vertical directions then to innerlayers through application of geological research, numerical simulation, lab core detection, nuclear magnetic resonance (NMR) and confocal laser scanning technology. From macroscopic perspective, there is less remaining oil scattering on the plane due to imperfect relationship between injection and production; Vertically, the top of sand body is where remaining oil richly gatheres.Alkali ASP flooding's effect is remarkable for remaining oil and heavy constituents of oil have dramaticly reduced, Especially for membranous remaining oil on the pore surface, and intergranular adsorption of remaining oil has added.
Daqing Oilfield is the earliest one to carry out ASP commercial field test and popularization, and has acquired abundant knowledge about it. But systematic evaluation and analysis of alkali ASP flooding hasn't been formed for there lacks further understanding of reservoirs’producing performance and remaining oil's distribution after alkali ASP flooding. In the A block of thick reservoir alkali ASP commercial field test which has been finished, there are 258 wells newly drilled (including 1 sealed coring well) with well spacing density of 177 wells/ km2.Dynamic data and coring wells’data from the test area are effectively combined with newly-drilled wells’logging information to study microscopic remaining oil in the cores before and after ASP flooding; Meanwile, Methods such as statistic analysis, core displacement, numerical simulation, nuclear magnetic resonance, Carbon/oxygen spectral logging, and dynamic comprehensive analysis are applied with confocal laser scanning technique to ideally detect and analyze remaining oil's type and distribution. It will provide guidance for further adjustments during alkali ASP flooding and for EOR research after ASP flooding.
Assessment of Post-Expanded Mechanical Performance of Materials and Evaluation of Material Expandability Limit
Authors: Bufalini A. , Morana R. , Nice P. I. , Bailey B. M. 
Published: October 2012

Abstract
The expandable tubular technology has seen an increased diffusion in the well construction process. However, while it is accepted in well remediation activities, the consideration given to expandable technology as a primary option for well design is limited. The confidence of the casing material performance after expansion remains one of the main factors in preventing a larger adoption rate. Extreme expandable applications require very high expansion ratios, thus exceeding the elongation to failure of conventional casing materials; even specially selected casing materials are close to the limit of their deformation capability.
Consequently, Statoil decided to extend the scope of a previous research program on materials for expandable applications to include an initial investigation into defining a material's expandability limit. A selected carbon steel grade was analyzed using specific experimental test methods and Finite Element Analysis (FEA), and employing previous results of other carbon steel grades and alloys.
The experimental activities involved tensile tests on post-expanded material using optical systems for the strain measurement, a technique previously adopted for as received material. This method allowed the determination of the true stress-strain curve far beyond the range of standard methods. The uniformity of mechanical properties after expansion was also investigated. The test results showed the carbon steel grade investigated maintained a significant deformation capability even after large expansions.
The FEA campaign analyzed the same materials using a 3D model, which incorporated the pipe eccentricity, to explore other cases and to verify the initial outcomes of expandability limits. The results allowed for the determination of a maximum deformation limit for the materials allowing a successful expansion.
Productivity Index and Inflow performance of Hydraulically Fractured Formations
Authors: Al Rbeawi S.. , Tiab D.. 
Published: October 2012

Abstract
Productivity index and inflow performance of horizontal wells intersecting multiple hydraulic fractures are of great importance. This importance comes from the fact that the fracturing process has become a common stimulation technique in the petroleum industry. However, few models for the productivity index and inflow performance have been presented in the literatures due to the complexity governing this topic.
This paper introduces a new technique for estimating the pseudo-steady state productivity index of horizontal wells intersecting multiple hydraulic fractures. Based on the instantaneous source solutions for the diffusivity equation, seven analytical models have been derived for different source solutions. Four of them represent the effect of the formation height and fracture height (the vertical direction), while the other three represent the solution for the horizontal plane. For vertical hydraulic fractures, the four solutions of the vertical direction, representing the pseudo-skin factor, are almost neglected. The three horizontal plane solutions are the main parameters that control the productivity index and inflow performance of the fractured formations. In this technique, the horizontal wells are acting in finite reservoirs where the pseudo-steady state flow is expected to develop. Reservoir geometry, reservoir properties, and fracture dimensions were considered in this technique. The number of fractures and the spacing between them were also investigated in this study. A new analytical model for estimating the required number of hydraulic fractures has been introduced in this study based on the reservoir drainage area and the surface area of fractures.
The models have been used to establish several plots to estimate the shape factor group based on the number of fractures and the half fracture length. This group is one of the main terms in the productivity index model. Several plots for the shape factor of fractured formations have been introduced in this study. The results obtained from the new technique have been compared with the results from previous models. Several numerical examples will be included in the paper.