bluuebunny/crossref_metadata_2025_split huggingface dataset:
Coiled Tubing Jet Drilling With a Downhole Intensifier
Authors: Kolle J. J. , Theimer K. , Theimer A. , Cox R. , Schershel S. R. 
Published: April 2008

Abstract
High-pressure rotary jet drilling holds the promise of increased rate of penetration with reduced weight-on-bit, torque and vibration levels. A high-pressure rotary jet drill, pressure intensifier and gas separator have been developed to allow jet drilling using conventional surface pumping equipment and coiled tubing. High-pressure reaction turbine jet rotors have been developed for drilling holes ranging from 1-1/8" to 3-5/8". Jet drilling tests have shown that 70 MPa (10,000 psi) jets can effectively drill most conventional oil and gas producing formations. Conventional pumps, swivels and tubing operate at up to 28 MPa (4000 psi). A 2.5:1 pressure intensifier was developed to allow jetting at the pressure required for effective drilling. The intensifier can operate on two-phase flow using a downhole gas separator. In two-phase operation the separated gas is used to power the intensifier and the high-pressure water is provided to the jetting nozzles. The gas exhaust from the intensifier is ported to the drilling head to extend the range of the jets.
Tests have demonstrated that the jet drilling BHA is capable of cement milling but rates of penetration are lower than a motor and mill and the pumping pressures required are higher. The tools could find applications in situations where a motor cannot be used. For example the tools could power a small diameter lance jet drill through an ultra-short radius curve for lateral drilling. Well service applications include removal of hard scale without risk of damage to damage to downhole equipment.
Cutting Concentric Casing Strings With Sand Slurry
Authors: Hebert Galen Roy , Sackash Mark , Hogan Richard 
Published: April 2008

Abstract
Operators needing to cut single or concentric casings to facilitate well abandonment or for other purposes can use a slow-rotating hydroblast motor with a jet cutter head on drillpipe. This combination is capable of operating with tight clearances.
This case history describes an operation wherein a jet cutter on a rotating motor was used to cut two components of a casing string, a 7-in. liner inside a 9 5/8-in. casing, at 400-ft depth. The well required abandonment, and the casing string was damaged, with a sharp bend that limited the tool size that could be used.
Chemical cutting and mechanical cutting were considered, but the casing damage and size limitation it imposed caused the service company to recommend deployment of a slow-rotating motor and jet cutter head conveyed downhole on 2 7/8-in. drillpipe. The slurry pumped through the cutter was sand carried by seawater, gelled with a polymer. The 7-in. liner was cut first and removed from the well. The 9 5/8-in. casing was cut and removed to enable well abandonment procedures.
The paper presents (1) discussion of the issues that led to use of the rotating motor setup, (2) treatment plan, and (3) execution procedures.
Planning for Successful Rig Assist HP/HT Cleanout Operations
Authors: Lamont Alan , Radcliffe Paul , Klinck Mark , Brumfield John , Bell Gavin 
Published: April 2008

Abstract
This paper describes the equipment and techniques that were used for a high-pressure, high-temperature (HPHT) cleanout operation carried out on the Shearwater platform in the UK central North Sea with the support of a jackup drilling unit. The project involved intervention in three wells over a period of 9 months. The wells had been shut in for some time following production of reservoir solids. A hydraulic workover unit (HWU) was selected to clean out the production tubing to allow isolation barriers to be installed.
In rig-assist mode, the HWU deploys pipe against surface pressure with the rig providing pipe-handling support. The paper details the planning and pre-engineering work that preceded offshore operations. Detailed planning and risk assessment were also required during operations because well conditions changed. Some equipment problems required a review of planned operations, and during an annual process plant shutdown, onshore tests were carried out before mobilization for the second phase of the intervention project.
Modifications were required to the HWU to withstand the high buckling loads associated with snubbing against high pressure. Additionally, special downhole tooling was required to accommodate extreme well conditions. The paper discusses the development work involved and the subsequent performance of the equipment.
Operating performance statistics and key lessons learned during the project are presented.
Unique Application of Coiled Tubing and Inflatable Packer Technology Leads to Successful Deoiling of Damaged Pipeline in Gulf of Mexico
Authors: Quintero Ignacio , Murphy Bob , Maddox Joe , Noddin John , Coles Robert 
Published: April 2008

Abstract
In July 2005 during Tropical Storm Cindy the pressure balance safety joint on the 8" crude oil riser at the West Delta 109A platform was separated. Subsequently, measures were taken to de-oil the first 5000ft. of the separated end of the pipeline. Before further action could be taken, Hurricane Katrina passed through the area resulting in further movement of, and substantial damage to, the pipeline. Divers did locate the line at a point some 4500ft from the platform and subsequently discovered that some 7000ft. of it was buried under mudslides further downstream of the platform.
The pipe line damage could not be repaired due to its' being buried under mudslides, therefore a unique approach was taken. Cuts were made at each end of the damaged pipeline, flanges and shut off valves were installed and a 4" pipe riser was then made up to one end, picked up and tied back to the service barge some 500 ft away thus creating an engineered radius suitable for coiled tubing (CT) operations. The CT unit was then made up at an angle of 15° to the vertical and an inflatable plug run into the riser, thence into the 8" line until it could go no further. The plug was then inflated and tested, the disconnect was activated and the crude oil in the line flushed out with sea water to the barge tanks until the returns were clean. The CT was pulled leaving the plug in place and the same procedure was repeated at the other end of the damaged section. In this way some 4190ft of the buried line was safely de-oiled leaving the balance isolated between the two inflatable plugs.
In this paper the authors will review the pipeline damage and discuss the various options considered to make the line safe and prevent leakage and environmental damage in the future. They will go on to describe in detail the preparation for, and the successful performance of, this CT deployment, the first of its' kind in the Gulf of Mexico. They will conclude that this pioneering operation can serve as a model for several such pipeline situations which the MMS has mandated should be fixed by 2010.
Case History: Extended-Stroke Downhole Power Unit Successfully Pulls Subsea Wellhead Plugs
Authors: McDaniel Dennis , Cromb John , Walton Jim , Clemens Jack , Moore Darrell , Huggins Jeff 
Published: April 2008

Abstract
As exploration continues to venture into more challenging environments, service companies have had to increase their scope of capabilities to meet the challenges brought about by the new environments into which the oil and gas industry has ventured. One of these areas has been the deepwater subsea arena. This paper will focus on one of the slickline innovations — an extended-stroke electro mechanical device — that enables performance of deepwater subsea well interventions more cost-effectively than other service alternatives.
Today's needs to provide deepwater subsea well servicing has created many new challenges for the industry. For example, pulling a deepwater subsea wellhead or crown plug can require an extreme pulling force. The difficulties experienced can be compounded by conditions that occur when the plug has been in place for extended periods of time as well as the more demanding deepwater conditions, such as high differential forces and settlement on top of the plug that contribute to the need for the higher pulling forces. These conditions often exceed the capabilities of conventional slickline services.
An option that has met other challenges in difficult scenarios is a slickline-deployed electro-mechanical device that produces a high linear pulling force directly at the wellhead plug without jarring. This tool does not require explosives or hydrostatic setting tools because it is operated by batteries. Since first being introduced, the electro-mechanical device has undergone several changes that have increased its capabilities and functionality. For example, it has recently been configured for pulling subsea wellhead plugs.
This paper will present a case history that details the first use of the ‘extended stroke’ electro mechanical device in the Gulf of Mexico in which it was capable of pulling plugs at a water depth of 5,339 feet. Using the electro-mechanical device with slickline instead of coiled-tubing resulted in a substantial savings in both the cost of deployment and rig time.
Extending Mature Field Life Using an Innovative Surface Controlled Subsurface Safety Valve (SC-SSSV)
Authors: Lalanne Philippe , Ducasse Alain , Barzu Emile , Millet François , Petit Hervé , Wallez Gery 
Published: April 2008

Abstract
A common cause of failure with surface-controlled, subsurface safety valves (SC-SSSV) is a defect in the down-hole hydraulic line, which controls the valve from the surface. Such a failure generates production losses and requires the intervention of a costly workover rig – usually not immediately available. In order to alleviate this type of situation, a system has been developed where the physical control line has been replaced by a communication system based on electromagnetic waves. The surface emitter continuously sends a signal to the SC-SSSV. Both items are designed to be fail-safe. The normally-closed valve remains open while receiving the signal and closes as soon as the signal is lost. This innovative, control-line free, wireline-retrievable SC-SSSV can be set in any landing nipple profile or anywhere in the tubing using monobore lock technology without a workover or well head modification.
The primary application is to secure wells with a damaged or blocked control line, damaged landing nipple, or wells completed without an SC-SSSV. It provides an immediate cost-effective solution – allowing production to resume with a surface-controllable safety barrier while avoiding or postponing a costly workover. With the arrival of this technology, sub-standard and temporary solutions, such as the normally-open velocity and ambient valves, no longer need to be considered. Another application is to free up a hydraulic SC-SSSV landing nipple in order to install a device like a capillary string for chemical or gas injection at the bottom of the well safely.
A prototype has been built and successfully tested for six months in a flowing gas well with 15% H2S – the case history is presented. The tool has proven to be easy to install and reliable. Deployment will start in 2008. Thousands of wells are concerned around the world.
This breakthrough slickline product offers new possibilities for safely and efficiently managing the countless failures of hydraulic SC-SCSSVs. Its versatility brings a reduction in production losses and provides the user with a cost-effective and reliable solution.
RFID Actuation of Self-Powered Downhole Tools
Authors: Snider P. M. , Doig Tom 
Published: April 2008

Abstract
The emergence, development and first implementation of RADIO FREQUENCY IDENTIFICATION (RFID) technology used to actuate self powered downhole tools are discussed. A case history is also presented.
Daily contact with RFID technology is all but inescapable. Typical uses include toll road monitoring, retail inventory control, banking and tracking of livestock and pets.
RFID as an enabling technology was recognized for its potential to replace and/or complement existing methods of downhole communication, such as wired coiled tubing and downhole tubulars, ball drop operations, fibre optics, i-wire and EM telemetry. Additionally, the prospect of actuating self-powered downhole tools created an attractive and potentially highly rewarding improvement in operating costs at the wellhead through a reduction in third party wellhead asset value, less time in the hole, reduced number of trips and multi functional capabilities.
RFID in this application has two inherent parts. The TAG, which is encoded with the appropriate command data.The READER which is housed in the downhole tool.
The encoded tag is released into the well at surface from where wellbore flow of fluids, gas or condensate transports it down the well tubulars until it passes through the reader antenna. The high power antenna within the downhole tool energises the passive tag then reads and stores the tag data. Typically the tag data will consist of a command to actuate the tool by means of a self contained hydraulic pump, electric motor and battery pack. Operations such as opening and closing valves, indexing and release mechanisms and a multiple of other functions can be implemented. Multiple tools can be run at the same time without compromising the tool internal diameter. Each tool has a unique address therefore tags can be coded with data that picks out an individual tool to be actuated. Time delays and repeat sequence commands are all possible.
The case history presented in this paper describes the use of this technology to open and close a drilling circulation sub. The tool was run by a North Sea operator as part of a drilling operation. The circulation sub was opened at a depth of 10,100 ft. by flowing an "Open" command tag from the surface. After circulating, the tool was closed by flowing a "Close" command tag.
Effective Approach for CT Interventions on Inaccessible Offshore Platforms in the North Sea
Authors: Cochran Jamie , Petrone Daniele , Clubb Alexander , Greig Scott 
Published: April 2008

Abstract
Approximately 50% of all installations in the UK offshore sector are small steel jacket structures that are normally unmanned. These platforms often have severe limitations on the permissible lift weight of temporary well servicing equipment. During a study into the extent of this problem, it was observed that a significant proportion of gas production is reliant on wells producing via these normally unmanned installations, and that production from this source has declined dramatically in recent years. When compared to manned installations where (intervention is easier and therefore assumed more frequent), production decline is less severe.
An operator identified a production enhancement opportunity on an unmanned installation in the North Sea UK Sector. The well needed extensive intervention in order to be brought back to production using coiled tubing (CT). Due to the restricted crane capacity (less than 7.5 ton) on the platform, a conventional CT package could not be lifted on board. Through a collaborative project, an existing CT equipment package was modified to be lifted within this weight limit.
A boat spooling technique was used to install the CT string onboard the platform without using a crane as it was much heavier than the crane limit. Throughout the equipment modification project, the principles of efficient rig up and optimized fast, safe working where applied. The installation of this equipment on the platform was conducted quickly and easily, validating this approach and improving on previous experiences significantly.
This paper demonstrates how conventional equipment can be adapted to meet the challenges faced with platforms considered inaccessible to perform CT interventions.
Innovative Tool for Coiled-Tubing Depth Measurement Increases Productivity and Minimizes Costs While Improving Accuracy and Safety
Authors: Ohaegbu Paul I. , Minish Sheldon , Morris Collin , Boyd Doug 
Published: April 2008

Abstract
Traditionally, coiled tubing (CT) counters have been mounted above the injector and typically on a levelwind between the coiled tubing reel and the injector. This tends to expose the coiled tubing counter to vibrations, jerks and slippage as the levelwind traveling head assembly slides from side to side and the coiled tubing is run in to the well or pulled out of the well. As a result of this exposure, the depth measurement accuracy of traditional coiled tubing counters is compromised. In the shallow gas market of the Western Canadian Sedimentary Basin, the error in depth measurements associated with coiled tubing velocity strings has been found to be significant and around 6 metres. Depth confirmation is typically then carried out using slickline. As a result of the error in depth measurement and the additional depth confirmation activity during the installation of the velocity string, the overall job time, the cost of operations and exposure of personnel at the wellsite are significantly increased.
Select Energy Systems, Inc in partnership with Count-Rite Oilfield Services, Inc., has developed a length measurement tool for coiled tubing, the SelectRite coiled tubing counter. The SelectRite CT counter is installed below the injector, and field tests have shown that it eliminates the limitations of traditional coiled tubing counters highlighted previously. Data transfer from the counter to the electronic display is wireless.
Currently, four operators in Western Canada will not land their velocity strings without using Select Energy's coiled tubing counter. For all these operators, accurate surface depth measurements have been achieved using the counter, thereby eliminating the requirement for additional depth confirmation and related personnel on the jobs.
This paper discusses Select Energy's coiled tubing counter which is designed for use with CT outside diameters (OD) of 19.05 mm to 50.8 mm and is currently being used mainly for coiled tubing completions operations in Western Canada.
Quick-Rigup HWU Barge-Assist Operations in the Gulf of Thailand
Authors: Robichaux Dicky , Henning Keith 
Published: April 2008

Abstract
This paper describes the results obtained and the equipment and techniques used in setting up the first barge-assisted hydraulic workover operation in the Gulf of Thailand (GOT). This paper will discuss the hydraulic workover unit (HWU) selected to perform the operations along with the engineering modifications that were required to meet the operator's requirements in the GOT, primarily installing electrical submersible pump (ESP) completions in depleting wells.
The paper includes descriptions of the challenges faced in operating an HWU on minimum facility production installations (MFPI) with total platform weight limitations of 40 mT and minimal crane capacity. Also discussed are a number of innovations designed and built into the HWU to enable a safe, quick assembly using a barge crane and remote power and fluid systems to make the HWU system as flexible as possible to cover all known deviations from the standard scope of work.
Lessons learned from the operations are also presented to demonstrate the ongoing operational challenges, the solutions implemented, and the results achieved.
High-Volume Wellwork Planning and Execution on the North Slope, Alaska
Authors: Cismoski D. A. , Rossberg R. S. , Julian J. Y. , Murphy G. , Scarpella D. , Zambrano A. , Meyer C. A. 
Published: April 2008

Abstract
BP Alaska Wells Team executes the highest wellwork volume in all of BP's worldwide operations. On the North Slope of Alaska, BP plans and executes wellwork for all of the fields it operates including Prudhoe Bay. This paper describes the process and use of technology to effectively plan well interventions, manage "the hopper", prioritize operations, monitor jobs in real-time and document lessons learned. A physical description of the BP Alaska's Wells i-Center will be provided too. The BP Alaska Wells Team executes over 40 well interventions every day in harsh arctic conditions as cold as -40 F. Effectively planning this many operations in the field and reporting back results to the office-based production engineers requires an effective process and use of technology. BP Alaska's hopper management and reporting systems and the role of technology to view operations in "real time" will be described.
This paper will also describe the planning process beginning at the point the production engineer has decided on the well intervention plan. The paper will continue explaining the planning process, describing the tools and general procedure used to organize and prioritize the 800 interventions in the hopper, monitor the execution of this work in "real time" and document lessons learned for similar future operations. Current equipment must be utilized at a high efficiency due to long lead times to get additional equipment. Thus, the jobs that are undertaken must be planned effectively, orchestrated with support equipment, to maximize equipment utilization and minimize stand-by time. In addition, any mistakes or best practices should be documented and incorporated in future well intervention plans.
Relationships between velocities of pulmonary venous flow and plasma concentrations of atrial natriuretic peptide in healthy dogs
Authors: Hori Yasutomo , Ukai Yoshimi , Uechi Masami , Hoshi Fumio , Higuchi Sei-ichi 
Published: April 2008

Abstract
Objective—To investigate the relationship between velocities of pulmonary venous flow (PVF) and plasma concentrations of atrial natriuretic peptide (ANP) in healthy dogs.
Animals—7 healthy Beagles.
Procedures—Dogs were anesthetized, intubated, and positioned in left lateral recumbency. Lactated Ringer's solution was infused (200 mL/kg/h) for 60 minutes via a cephalic vein. Transmitral flow and PVF velocities were measured echocardiographically by use of the apical 4-chamber view. Pulmonary capillary wedge pressure (PCWP) and ANP concentrations were determined.
Results—IV infusion significantly increased heart rate and PCWP. Similarly, the ANP concentration significantly increased from baseline (before infusion of lactated Ringer's solution) values. Transmitral flow velocities were significantly increased, although the ratio of velocity of the flow during early ventricular diastole (E wave) to velocity of the atrial flow (A wave; E:A ratio) was unchanged. Regarding the PVF velocities, forward flow during ventricular systole (S wave) and retrograde flow during atrial contraction were significantly increased, whereas velocity of the forward flow during ventricular diastole (D wave) was unchanged. Ratio of the velocity of the S wave to velocity of the D wave was increased significantly, and this ratio was significantly correlated with PCWP or ANP concentration. However, the E:A ratio was not correlated with PCWP or ANP concentration.
Conclusions and Clinical Relevance—PVF velocities were strongly correlated with PCWP and plasma ANP concentration in clinically normal dogs. Therefore, PVF velocities may serve as a sensitive indicator and provide additional information for monitoring acute preloading conditions and estimating atrial filling abnormalities in dogs.