bluuebunny/crossref_metadata_2025_split huggingface dataset:
High-Temperature Conformance Field Application Through Coiled Tubing: A Successful Case History
Authors: Ramirez G. , Arredondo G. , Chapa J. , Macias R. , Soriano J. E. 
Published: July 2010

Abstract
Jujo Teco is one of the most important oil fields located in southern Mexico. It produces an average oil gravity of 35 API, which is combined with the heavy oil from offshore Mexico to enrich the Mexican oil blend. Sustaining oil production rates is one of the main targets for this mature field, and controlling the water produced is one of the primary challenges to keep the oil production up to the desired levels. Performing conformance treatments in this field is also a major challenge. Formations to be treated are naturally fractured carbonates averaging depths of 19,000 ft with bottomhole temperatures above 300°F. They are completed in openhole sections with typically 300 ft of exposed formation. It is especially difficult to address if the water-control treatments are bullheaded because there is no way to distribute and place the fluids in the right zone without the risk of sealing off the oil producing sections.
Using coiled tubing for placing these types of treatments has been a viable alternative to increase the rate of success on these deep, openhole completions in conjunction with the introduction of a high-temperature conformance polymer. The cases presented in this paper show how the water cut has remained almost zero in some instances, even when the treatment was performed three years ago.
Application of Heavy-Duty Wireline Fishing Tools and Techniques Solves Complex Problem and Restores Well to Production
Authors: Trujillo G. J. C. , Vincent J. M. , Robertson N. 
Published: July 2010

Abstract
The Oropendola Field is located in the Llanos Basin of Colombia and production from the wells is typically augmented by means of artificial lift methods, particularly the jet pump. During a recent routine wireline campaign to install a jet pump in a sliding sleeve, difficulty was experienced in releasing the assembly from the running tool and so it was extracted, but became lodged and eventually the running tool released leaving a fish in the hole. There followed several unsuccessful attempts to recover the fish but with each successive attempt the situation kept deteriorating and so fishing operations were suspended while the options were considered: Continue with fishing operations to try to clean up the well.Work the well over.
The latter option was considered financially unattractive so the former choice was made but the situation was so complex that it was decided to bring into the country a heavy duty Wireline fishing specialist to assist. His brief was to evaluate the well along with the client and the local wireline personnel, to put a plan in place for the recovery process to begin and to supervise operations to clean the well up. After a full review of the equipment available and the number and type of fish that needed to be recovered, an operational plan was compiled and operations begun using the on site wireline unit and ancillary equipment. Early problems with the relatively low strength of standard pulling tools lead to a further review of tooling and a set of heavy duty fishing tools being imported, upon receipt of which operations continued. After a total of 59 trips into the well, with no miss-runs and no failures, all of the fish were successfully recovered and a new jet pump assembly was run and landed successfully allowing the well to be brought back into production 26 days after arrival of the specialist on site.
In this paper the authors will review the operations that lead to the complex fishing problem, the tools imported and the reasons for them. They will go on to describe in detail the fishing operation which utilized equipment with lower than ideal load capabilities and the detailed evaluation process of each wireline tool string run which eventually lead to the well being cleaned up and its production capacity restored
Pioneer Coiled Tubing Intervention Onboard Floating Production Storage and Offloading Vessel (FPSO) Offshore Brazil
Authors: Pinto J. C. , Guimaraes Z. , Almeida V. A. , Raimundo L. S. , Bessa J. A. 
Published: July 2010

Abstract
FPSOs (Floating, Production, Storage and Offloading vessels) are ships with capacity to process, store and transfer oil. On the deck of the ship, there is a processing plant which separates and treats fluids from the wells. After separation, the oil is stored inside the vessel cargo tanks and, periodically, it is offloaded into a shuttle tanker through loading hoses.
The biggest FPSOs have capacity to process about 200 thousand barrels of oil per day. They are a good solution to develop exploration projects in offshore oil fields, especially in deep water, due to the comparatively low initial investment, short time for installation and great operational flexibility. However, FPSOs can experience problems arising from scale deposition in flexible sub-sea hoses.
Recently, in order to explore giant offshore oil fields in Brazil and to avoid the high installation cost of a great number of sub-sea pipelines, VLCCs (Very Large Crude Carriers) have been converted into FPSO's.
Over time, some of these converted floating plants have suffered production drops due to the obstruction of both production and gas lift lines by hydrate or scale depositions.
In many of these FPSOs, the reduced space and the lack of cranes in the areas close to the flow line access points were a barrier to restoring lost oil production. In some cases, it was necessary to shut-in production from some lines for several months to allow for the installation of a work-over rig. The financial consequences of such shut-in's were extreme.
In order to restore production faster and with lower cost, a pioneering method of intervention in FPSO production and gas lift lines was developed based on the use of coiled tubing.
This paper presents case histories of successful jobs that cleared two production lines and a gas lift line, including the description of logistics, rig-up process and operation of coiled tubing units in FPSOs. With minor modifications this method can be used in a wide variety of floating production vessels.
The FPSO is a floating, production, storage and offloading ship-shaped vessel. Production facilities are mounted on raised supports above the vessel deck. Reservoir fluids pass from subsea production wells, via flowlines and risers, up into the turret and then to the production facilities. Produced oil is stored in the vessel cargo tanks and periodically offloaded onto a shuttle tanker via a loading hose.
Lubricity of Brine Completion and Workover Fluids
Authors: Ke Mingjie , Foxenberg William 
Published: July 2010

Abstract
As the industry increasingly develops extended-reach, high-angle and deepwater wells, one of the considerations is fluid lubricity when designing a completion or workover fluid. Fluid lubricity plays an important role in choosing the optimum fluid for the operation.
This paper presents lubricity or coefficient of friction data for various completion and workover brines. Two commercial brine lubricants were also evaluated to determine their effectiveness in increasing brine lubricity. Results indicate that lubricity of brines varied with the type and concentration of salt, but generally increased with increasing salt concentration. For example, sodium and potassium brines behave differently as compared to calcium brines with regard to lubricity. Also, zinc bromide containing brines show very high lubricity, suggesting that using a lubricant is generally unnecessary. Furthermore, practical guidelines are provided to better design brine completion and workover fluids for well operations where reducing torque and drag is required. Case histories are also presented which successfully applied one of the lubricants in the fields.
Temperature and Salinity Effects on Drag-Reduction Characteristics of Polymers in Coiled Tubing
Authors: Shah S. N. , Vyas A. 
Published: July 2010

Abstract
Coiled tubing applications include drilling operations, hydraulic fracturing, well completions, removing sand or fill from wellbore, etc. These applications involve pumping fluids at high temperatures and salinity. Due to curvature effects in coiled tubing, huge pressure losses occur limiting the maximum flow rate achieved. By adding specific chemicals known as drag reducers to the fluids, these pressure losses can be minimized to a great extent.
Previously, several authors have published their results for fluid flow through coiled tubing but only a limited number of studies have been reported related to temperature and salinity effects on drag reduction in fluids flowing through coiled tubing.
This paper discusses experimental study of two commonly used drag reducers ASP-700 and ASP-820 flowing through coiled tubing with different salinities and temperatures. Both small-scale and large-scale flow loops have been utilized in this study. The small-scale flow loop includes a ½-in. OD smooth coiled tubing while the large-scale flow loop includes 2⅜-in rough CT. Elevated temperature tests and salinity tests are conducted using optimum concentrations of drag reducers in fresh water, 2% KCl, and synthetic seawater.
The flow data thus gathered were analyzed and used to develop correlations that can predict drag reduction at different salinities and temperatures. The developed correlations show reasonable agreement with experimental data.
Coiled-Tubing Intervention and Drilling System Using Cost-Effective Vessels
Authors: Millheim K. K. , Williams T. E. , Yemington C. R. 
Published: July 2010

Abstract
Deep water and ultra deep water intervention of wet trees has been a huge challenge for oil and gas producers. Currently, the only realistic way to do intervention is to use a conventional Mobile Offshore Drilling Unit (MODU) or intervention vessel (which is usually a smaller MODU) whether for a simple clean out or re-completing another producing interval. This is an extremely costly venture and the intervention is only scheduled when the economics of the operation are clearly justified. And even when the intervention is approved there is the problem of scheduling a MODU or intervention vessel. Sometimes the intervention can take months before a MODU or intervention vessel is available.
There is a new enabling technology, using a Self Standing Riser, (SSR), where a coiled tubing intervention and drilling system could be deployed by a cost effective vessel (not a conventional MODU) with all the coiled tubing and related equipment on the vessel. The SSR design is such that it would attach to the subsea tree and provide the support and a circulation conduit for the coiled tubing to have full circulation capabilities back to the intervention vessel. The vessel, itself, would have station keeping capabilities for a significant period of weather conditions for the Gulf of Mexico.
This paper presents the reasons why conventional and subsea coiled tubing approaches have been unable to provide a economically workable solution for coiled tubing intervention and drilling from wet trees in deep water. The paper describes a new system based on a SSR and a cost effective vessel (non MODU) design that could accommodate the coiled tubing equipment, and provide station keeping and support for the operations. The paper will discuss safety issues such as: the reliability and safety of the SSR, well control issues, emergency disconnects, and the event of a drive off by the vessel.
Unless, this type of technology is developed and deployed millions of barrels of barrels of oil and gas will remain behind pipe. In other cases, some fields will not be developed because the need for on-going intervention coupled with high capital costs that will not meet the economic threshold to commission the development.
Selective Fracturing of a Series of Perforations in a Horizontal Well Using a Resettable Straddle System
Authors: Thompson J. , Tomich M. M. 
Published: July 2010

Abstract
In the Viking formation in the Redwater Operations area of Alberta, Canada, horizontal wells are typically completed using slotted liners. Earlier wells were usually completed in the vertical and subsequent fracturing of the perforated interval would generally lead to productivity improvements. In a new horizontal well drilled early in 2009 it was decided to cement casing through the productive zone and then perforate several intervals and fracture them in an attempt to improve productivity. Fracturing of horizontal sections in the past has proved problematic with the use of diverters being ineffective and cup packers being unreliable, so a new approach to allow for selective treatment of each set of perforations was researched. As a result a selective “jet pack” straddle system was chosen which allows for setting it across the zone, fracturing, unsetting the straddle, circulating the well clean and providing for the possibility of moving it further uphole to treat the next set of perforations. The well was drilled to a total vertical depth (TVD) of 650 meters (2133 ft.) and a measured depth (MD) of 1481 meters (4859ft.), with a maximum inclination of 91°. A 4-1/2” 11.6lbs/ft casing string was then cemented in place and the well perforated with six sets of perforations each one meter in length with depths ranging from 817-1467 meters (2681- 4813 ft.). A straddle system was then deployed on 2-7/8” coiled tubing with the objective of selectively fracturing each interval with some 45 metric tones (99,180 lbs) of sand at pump rates of 12-16 Bbls/min with breakdown pressures ranging from 20-30 MpA (2900-4350 psi).
In this paper the authors will briefly discuss the history of the field and the evolution of the completion methods employed. They will go on to review the features of the straddle assembly and to describe in detail the selective fracturing operation which was performed in which the straddle was set and unset twelve times in six runs into the well. Productivity over the first 4 months was 50Bbls/Day, which is the longest & highest initial production rate in the field to date.
Scale Prediction and Inhibition for Unconventional Oil and Gas Production
Authors: Fan Chunfang , Kan Amy T. , Zhang Ping , Lu Haiping , Work Sarah , Yu Jie , Tomson Mason B. 
Published: July 2010

Abstract
With the advance of new exploration and production technologies, oil and gas production has gone to deeper and tighter formation than ever before. These developments have also brought challenges in scale prediction and inhibition, such as how to prevent scales at high temperature (150–200°C), pressure (1,000–1,500 bars) and TDS (&gt;300,000 mg/L) commonly experienced at these depths. This paper will discuss (1) the challenges of scale prediction at high temperature, pressure, and TDS; (2) an efficient method to study the nucleation kinetics of scale formation and inhibition at these conditions; (3) the kinetics of barite crystal nucleation and precipitation in the presence of various scale inhibitors and the effectiveness of those inhibitors. In this study, nine scale inhibitors have been evaluated at 70–200°C to determine if they can successfully prevent barite precipitation. The results show that only a few inhibitors can effectively inhibit barite formation at 200°C. Although it is commonly believed that phosphonate scale inhibitors may not work for high temperature inhibition applications, the results from this study suggest barite scale inhibition by phosphonate inhibitors was not impaired at 200°C under strictly anoxic condition and in NaCl brine. However, phosphonate inhibitors can precipitate with Ca2+ in a brine at high temperatures and, hence, reduce efficiency. In addition, the relationship of scale inhibition to types of inhibitors and temperature are explored in this study.
A General Coupled Kinetic Adsorption/Precipitation Transport Model for Scale Inhibitor Retention in Porous Media: II. Sensitivity Calculations and Field Predictions
Authors: Vazquez O. , Sorbie K. S. , Mackay E. J. 
Published: July 2010

Abstract
This paper describes the application of a generalised kinetic adsorption/precipitation (Γ/Π) model for scale inhibitor (SI) retention and transport in porous media. The context of this study along with the chemistry and mathematics of the model itself are described in detail in the related Paper I (SPE 130702). Here, we describe a wide range of sensitivity calculations using this model which illustrate both (i) the consequences of this model in laboratory core floods, and (ii) the field predictions which results from various assumptions about field adsorption/precipitation processes. To our knowledge, this is the first time that such a dynamic coupled Γ/Π model has been deployed in this way to scale inhibitor transport modeling.
This model can describe any combination of retention mechanisms (adsorption and precipitation) in either equilibrium or under dynamic (non-equilibrium).conditions. The calculations presented here also clarify the roles of adsorption and precipitation mechanisms and how they affect field squeeze return curves. These results (and related experimental work, Kahrwad et al, 2009) show that precipitation is a more important process at higher SI concentrations going over to pure adsorption at lower concentrations. These modeling results indicate how we may then exploit the roles of each of these different mechanisms in the high SI and low SI regimes. Simulations of the type presented here can also help to provide the "target properties" for SI systems (adsorption, precipitation and coupled adsorption/precipitation) of the future.
This generalized model formulation also unifies the various approaches by different "schools of thought" by developing a scheme which can model any processes as appropriate. We believe that that this work resolves the controversy between adsorption vs. precipitation as the main mechanism of SI retention and replaces it with a clear generalised consistent model which may describe when (i) pure adsorption or (ii) coupled adsorption/precipitation occurs.
A New Approach to Propagate Petrophysical Properties in a Fracture Network for Naturally Fractured Carbonate Reservoirs Case Study: Icotea Fault Shear Zone, Cretaceous Formations at Maracaibo Lake, Venezuela
Authors: Rodolfo Soto B. , Perez Sergio , Arteaga Duarry , Martin Cinthia 
Published: July 2010

Abstract
A fuzzy-logic approach accurately characterizes spatial porosity and permeability for a complex, naturally fractured carbonate reservoir. The reservoir lies in the Cretaceous section alongside the fault damage and shear zone at the downthrown block to the west of the Icotea fault, Central North segment of the Maracaibo basin.
To identify the pore type in our characterization of this carbonate reservoir, we first used fuzzy logic to obtain fracture indexes from conventional well logs. Then we used a resistivity/porosity model with cementation factor, m, variable to determine fracture porosity, and calculated total porosity from neutron-density logs. After that, we developed a neuro-fuzzy logic permeability model with porosity, shale volume, fracture indexes, and pore type as independent variables.
Next, we used directional-statistics tool analysis to identify the five main fracture families and categorize them. The diagnosis of fracture orientation relies on the statistical analysis of fractures from four wells, three of them having image logs and one having a direct description of fractures from an oriented core. We also compared the fracture-orientation data from well data with the faults interpreted at seismic scale to unravel their structural connection.
Fracture lengths are obtained from curvature maps by direct measurement of lineaments matching the azimuth of each family. A logarithmic fit of the known values allows extrapolating values of fracture lengths and spacings below seismic resolution. To propagate porosity in our fracture system, where only a seismic P-wave volume was available, we found for each fracture family a general inverse functional relationship between fracture intensity and fracture porosity, introduced as the r-pi method of correlation.
With a sigmoidal function we correlate the neuro-fuzzy logic permeability variable with the aperture and intensity of the fractures. With a statistically based characterization we identify wheter the fractures display directionally or stratigraphically related anisotropies. Finally, to populate petrophysical properties in the fracture network we apply the functions devised starting with the size of the fractures as an independent variable.
Nipple Profile Milling With Electric Wireline Interventions
Authors: Schwanitz B. J. , Aji A. , Collins J. P. , Henriques K. 
Published: July 2010

Abstract
Recently, a solution has been developed to provide for milling of nipple profiles and other downhole hardware with electric wireline. A new milling bit and milling system for the wireline miller enables nipple profiles to be opened up in diameter to allow larger intervention products to be deployed, e.g. straddle packers and insert valves. Extensive testing was conducted prior to the introduction of this service to optimize the weight on bit and torque. The result was the development of a unique version of the hydraulic stroking tool to be combined with the milling tool to provide the controlled weight on bit.
A major benefit of using the wireline milling system is the ability to provide precision milling without mobilizing coiled tubing (CT) or heavy surface equipment for circulating and handling fluids. Thus, there is no risk of damaging the reservoir from the circulating fluids. In addition, this kind of intervention can be performed more cost-effectively, involving less people, less heavy lifts and therefore, reduced HSE risks.
The world's first milling of a nipple profile on wireline took place in Indonesia where the wireline miller was mobilized to enlarge the nipple profiles in 10 wells. The entire operation was performed in 20 operating days and well kills were prevented, which would have been necessary if executing the operation with a conventional method, such as on CT. Major benefits included minimal reduction in production levels, precision milling with zero cuttings left in hole and no labour-intensive requirement for CT or heavy surface equipment.
As of December 2009, the ID of twenty (20) Super 13 Chrome nipples have been enlarged for one operator, without a miss-run related to the new milling system.
This paper will discuss the technical aspects of this new milling system as well as present the field performance gained to date through a field test and two case histories.