bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Study on Wax-Deposition Characteristics of a Waxy Crude Oil Under Single-Phase Turbulent-Flow Conditions
Authors: Swivedi Priyank , Sarica Cem , Shang Wei
Published: March 2015

Crude oil, having a paraffin nature, has been studied extensively in the small-scale flow loop at Tulsa University Paraffin Deposition Projects (TUPDP). The effects of turbulence/shear and thermal driving force on wax-deposition characteristics were experimentally studied using a waxy crude oil from the Gulf of Mexico. The test matrix consisted of a total of 15 experiments, which included 12 short-term tests and three long-term tests. The tests were conducted under different operating conditions with a wide range of Reynolds numbers from 3,700 to 20,500. The shear stress ranged from 5.4 to 53.9 Pa.

It was observed that paraffin deposition is highly dependent on the thermal effective driving force, which is the temperature difference between oil bulk and initial inner pipe wall, and also on turbulence effects. The deposit thickness obtained using both the pressure-drop method and a direct measurement was found to decrease with increasing shear stress and decreasing thermal driving force. The wax content showed a gradual increase with an increase in flow rate. For the short-term tests, the deposit mass with no entrained oil seemed to increase and then decrease with an increase in initial shear stress and decrease in effective thermal driving force, whereas the total deposit mass was found to decrease with an increase in initial shear stress or decrease in effective thermal driving force.
Reassessment of Multiphase Pump on Field-Case Studies for Marginal-Deepwater-Field Devolopments
Authors: Abili Nimi , Kara Fuat , Ohanyere Ifeanyi J.
Published: March 2015

Subsea-processing technology (SPT) is one of the frontier tools currently being explored by the oil and gas industry to open new opportunities and achieve more-effective exploitation of offshore oil and gas reserves. Exploration and production has moved into unlocking reserves that are less attractive and in difficult environments (e.g., marginal deepwater fields). These marginal fields are located remotely offshore and require one form of processing or another before they can be productive commercially. This paper focuses on the applicability of SPT employing multiphase pumps (MPPs) to develop marginal fields commercially. This was a result of the technology selection established by a comparison of performances of several SPTs for effective development of marginal fields using tools [e.g., quality function deployment (QFD)], and evaluated further using an analytical hierarchal process (AHP), resulting in the most effective innovative SPT for marginal-field development. The result from these tools was validated further in their applications to real-life fields, and this is achieved by specific field-case simulation studies using the OLGA transient multiphase flow dynamic model program to comercially develop marginal fields.
Improved Paraffin-Deposition-Profile Estimation in Hydrocarbon Pipelines and Effective Mitigation Review
Authors: Sheikh Mohammad Samiur Rahman , Chacko Sibi
Published: March 2015

Flow of paraffinic hydrocarbon liquids within extended pipeline networks orwells, where the environment/bulk temperature is below the cloud point orwax-appearance temperature (WAT), could result in precipitation of wax from thebulk fluid. Precipitated wax crystals from crudes deposits on the inner pipewall could lead to reduced flow area or even complete blockage and couldpresent a costly problem in the production and transportation of petroleumproducts. Timely removal of such deposits is extremely important to avoidassociated problems. This paper illustrates a numerical approach to estimatethe deposition profile and its effect on flow-related parameters. Later, theprocedure is validated with field data from a North Sea offshore productionfacility. This paper also seeks to propose a feasible solution to avoid suchflow-assurance issues; in doing so, current commonly practiced reduction andpreventive methods are reviewed. Previously, providing thermal insulation withaerogel foam had proved to be the most effective option in preventing wax fromprecipitating. A relatively new approach is discussed in this paper, whichallows for minimizing the usage of insulation material in an attempt to reducethe implementation cost of the proposed precaution. Theoretical implementationof the procedure was also conducted to identify its effectiveness, which waslater found to be elimination of the deposition completely.
Optimization Study of a Novel Water-Ionic Technology for Smart-Waterflooding Application in Carbonate Reservoirs
Authors: Yousef Ali , Ayirala Subhash
Published: March 2015

Injection water with selective ionic content and composition is a key requirement for smart-waterflooding (SWF) application in carbonate reservoirs. Smart water--depleted in monovalent ions, but enriched in sulfates and divalent cations--is desired for incremental oil recovery in carbonates, which constitute complex water chemistry when compared with sandstones. Most of the published work available in this area is focused on addressing water-chemistry requirements for low-salinity waterflooding in sandstones. However, none of these studies describes the complex injection-water requirements of SWF in carbonate reservoirs. Also, injection-water chemistry has a known impact on several tertiary enhanced-oil-recovery (EOR) processes among the three major categories of chemical, gas, and thermal EOR. The main purpose of this study is, therefore, to identify and optimize a novel water-ionic technology that can serve as a “one-shop solution” to generate desired water chemistries suited for different improved-oil-recovery (IOR)/EOR processes, including SWF in carbonates. A novel water-ionic technology, comprising nanofiltration and reverse-osmosis membrane-based processes, was identified for optimization in this study. The proposed technology makes use of these two membrane-desalination processes in parallel configuration to provide multiple water streams of widely varying ionic strength and content. Different water streams obtained from this novel solution can be blended effectively to yield a smart-water cocktail of desired ionic strength, composition, and monovalent- to divalent-ion content suited for carbonates. Smart-water cocktails obtained from the proposed solution are also suited for application in other EOR processes such as polymer flooding, alkaline/surfactant/polymer flooding, low-salinity surfactant flooding, dilute surfactant flooding, carbonated waterflooding, and miscible gasflooding, and are suited for boiler feedwater in steamflooding. The optimized scheme thereby offers a novel one-shop solution to meet the complete suite of desired water-chemistry requirements for different IOR/EOR processes. In addition, comparative evaluation-study results between novel water-ionic technology and other already-known advanced-desalination schemes highlight the major advantages of the new solution in terms of better water-ion-tuning flexibility, higher recovery efficiency, lower energy requirement/footprint, and ease of operation.
Multifaceted Approaches for Controlling Top-of-the-Line Corrosion in Pipelines
Authors: Frenier Wayne W. , Wint David D.
Published: March 2015

This paper reviews the mechanisms of initiation and the prevention of top-of-the-line corrosion (TLC). Practical, multifaceted techniques based on the most recent research and developments will be described and then illustrated with documented sources to arrive at the best practices for control of this significant corrosion manifestation. The rapid expansion of the production of oil and gas from unconventional sources requires the annual construction of thousands of miles of new pipelines, which will experience a bewildering and changing range of conditions that will require the use of new and innovative internal-pipeline-corrosion-protection methods that have been tested in field applications. These new corrosion-protection methods will be needed because of the complex corrosive environment of multiphase- and stratified-flow pipelines (including gathering lines), which is frequently observed in new shale-play production. Conventional corrosion-inhibition methods (continuous or intermittent injection) may not be effective for inhibiting the pipelines because physical contact of the inhibitors is difficult to achieve in multiphase flowing systems at the top of the line (TOL). In addition, the pipelines must be piggable to be cleaned and treated properly, and traditional slug- or continuous-treatment methods have been found to be less than adequate where conditions exist for TLC to occur. Several innovative methods are being developed to provide effective and long-lasting protection to the entire pipeline surface, including the use of pig trains with inhibitor slugs, improved inhibitor chemistries, inhibitors added to gels and foams, and special pigs that provide a 360° spray of inhibitor chemicals. The newer methods will be compared with the older technologies.
Innovative Solutions Enable Production Start of China's First Marginal Subsea-Tieback Oil Field
Authors: Jiayou Mao
Published: March 2015

Liuhua4-1 (LH4-1) oil field is located 215 km southeast of Hong Kong in the South China Sea. The field was first discovered in 1987, but because of economic and technical challenges, it was not until 2012 that the development of this field became a reality. The 300-m-water-depth oil field was successfully tied back to an existing oil field [Liuhua11-1 (LH11-1)] through subsea pipeline, power cable, and multiplex control umbilical. The project executions included disconnection, life extension, and reconnection to the existing oilfield floating-production system (FPS). It was also China's first tieback subsea development project. To develop this marginal oil field, a number of technical challenges were overcome through a series of new technologies, and their successful development and implementation.
Study on Severe Slugging in an S-Shaped Riser: Small-Scale Experiments Compared With Simulations
Authors: Park Sangmin , Nydal Ole Jørgen
Published: March 2015

Severe slugging is a transient multiphase-flow phenomenon that can occur in pipeline-riser systems, particularly in offshore production of oil and gas. It is characterized by large pressure fluctuations at the base of the riser and is accompanied by fluctuations in fluid delivery from the top of the riser. This unstable phenomenon is undesirable because production and equipment are affected adversely by the large pressure and flow-rate fluctuations. In this study, air-/water-flow experiments have been carried out at the S-shaped-riser facility in the multiphase-flow laboratory of the Norwegian University of Science and Technology (NTNU) and have been compared with results from a flow simulator (OLGA). The results obtained in the work show that stability maps, pressure amplitudes, and slug frequencies are in acceptable agreement with each other; however, some deviations are seen regarding the slug frequencies at low flow rates.
Barzan Onshore-Gas-Facilities Construction: Attaining Excellence Through a Comprehensive SHE&S Management System
Authors: DeHart Robert E. , Brand Johnny
Published: March 2015

The Barzan Onshore Project is being developed by Barzan Gas Company Limited, a joint venture between Qatar Petroleum and ExxonMobil Barzan Limited, with RasGas Company Limited (RasGas) assigned to develop and operate the facilities upon completion. The engineering, procurement, and construction (EPC) work is being carried out by JGC as the primary contractor. JGC has subcontracted the construction execution of the work to eight major subcontractors. The project achieved 131 million man-hours without a lost-time incident from July 2012 to March 2014. The workforce peaked at more than 29,000 (or approximately 30,000) persons from multiple countries. This paper describes the overall safety, health, environment, and security (SHE&S) management system as a three-tier model based on the EPC contract in which there are 211 SHE&S contract-related deliverables (in eight general categories) that are measured monthly by means of the SHE&S work-activities schedule. The system pertains to all parties (i.e., RasGas, JGC, subcontractors, vendors, suppliers), and this rigorous monthly accounting helps drive overall SHE&S performance. The contract combines a highly prescriptive and goal-setting approach. The project has a strong leadership team, which has exhibited daily visible commitment to SHE&S from project outset and has solidified the success of the program. Care and concern for the welfare of workers have been top priorities for the leadership team. The systematic approach combined with the leadership team's efforts has delivered a great foundation on which to build and sustain SHE&S performance at site.
Slickline/CTU Deployed Scab Liner System Eliminates Use of Workover Rigs and Reduces Cost
Authors: McLeod J. , Brown M. J. , Diller C. , Harris R.
Published: March 2015

A new rigless stackable pipe system has been developed for running scab liners in damaged production liners or for improving well conformance. The system is designed to be lubricated and run through tubing under pressure and has been successfully deployed in Alaska. This paper details the development, testing and a field trial of this scab liner system. This system has a connection that snaps pipe sections together and is unique in that it allows a much larger internal diameter than other stackable systems. For regions where rig workovers are expensive such as offshore or the North Slope, using the stackable system for scab liners can save up to 90% of the cost of a rig workover. The snap latch pipe is deployed with a combination of slickline and coiled tubing for scab liners. The snap connection is available for use with 2-7/8″ and 3-1/2″ base pipe. Slickline sets a float assembly with a releasable anchor in the tubing then stacks the sections of float equipment and pipe for the required length of the scab liner. The final slickline run is to set a sleeve with a profile and polished bore for coiled tubing operations. Coiled tubing then picks up the entire scab liner and shears the anchor, then runs the liner to depth. On the second run, coil cements the liner in place. A field test of the system was performed in a well with a few sections of pipe prior to deployment in a well for an actual intervention. The target well for the intervention was an injection well on the North Slope. The well had a thief zone that was taking too much injection water and conventional cement squeeze techniques were unsuccessful at shutting off the thief. A cemented scab liner was proposed to isolate the thief zone. A 557′ scab liner was successfully deployed and cemented in place. Target intervals were perforated and the well was put on injection. Details of the design, testing and deployment of the scab liner are outlined in this paper.
Coiled Tubing Intervention Riser System
Authors: Courtois Coy , Mebarkia Sid
Published: March 2015

Chevron's portfolio of subsea assets in the Gulf of Mexico is poised to more than double in the next 5 years starting with First Oil of Jack/St. Malo, the development of Buckskin Moccosin, and the expansion of its exisiting Tahiti and Blind Faith subsea development assets such as Tahiti 2 and Blind Faith 2. Subsea well recovery rates typically underperform when compared to their surface well counterparts. One significant factor is the relatively high access costs for subsea well intervention. Without frequent intervention to maintain well performance, a lot of barrels are left behind. At Blind Faith Chevron is investigating platform-based intervention alternatives that dramatically improve economics by reducing or eliminating the need for vessel-based intervention. A key enabler is the Coiled Tubing Intervention Riser (CTIR) system that creates a direct vertical access point to the flowline riser from the platform. With the flowline accessible by coiled tubing, services such as acid stimulation, artificial lift, hydrate remediation, etc. become feasible. The reach of the coiled tubing is limited to the pipeline end terminations of the riser flowlines making direct vertical access to the subsea trees still a job for the large, expensive vessels. The CTIR system does not replace the need for vessel-based intervention, but it does support some well intervention options.
Extending Coiled Tubing Frontiers to Ultradeep, High-Pressure Well Interventions in Deepwater Gulf of Mexico: A Technical Feasibility Study
Authors: Rudnik Alexander , Nava Carlos Alberto , Grunichev Renny Alexis , Gortmaker Travis , Nwabuzor Charles
Published: March 2015

Coiled tubing (CT) is a well-established well intervention technique in deep water (1,001–4,999 ft [305–1,523 m] water depth) offshore environments in the Gulf of Mexico (GOM). Wells as deep as 25,000 ft [7,620 m] measured depth (MD) are routinely accessed, serviced, and abandoned with CT at the present time. However, as demand for oil and gas continues to increase, the industry is now expanding its activities into ultradeep waters (water depths greater than 5,000 ft [1,524 m]), ultradeep reservoirs (well depths greater than 30,000 ft [9,144 m]) and high pressures (maximum shut-in pressures close to 15,000 psi [100 MPa] at the seafloor and greater than 10,000 psi [69 MPa] at surface). Ultradeep water projects are becoming central to the overall deep water investments being made by the major oil & gas operators, with several projects slated for 2015.

Coiled tubing is considered one of the critical contingency operations that may be required during the completion of these ultradeep high pressure wells. CT interventions are also expected to be part of future well workover/maintenance operations. The extreme downhole and surface conditions that exist in these ultradeep high pressure wells pose many significant challenges to the CT industry, as it strives to provide safe and reliable access to these wells. In order to address some of these challenges, the CT industry has to re-evaluate various aspects of its coiled tubing design and operations, including the minimum yield stress of the pipe material, surface equipment, downhole tools, fluids, and wellbore access modeling software in order to identify any technology gaps that may affect its ability to effectively service these ultradeep, high-pressure wells. Once these gaps have been identified, they must be converted into specific action items to be addressed by all parties, ranging from service companies and equipment manufacturers to operators.

This technical feasibility study on coiled tubing deployment for an ultradeep high pressure project in the GOM describes the evaluation criteria used, identifies technology gaps and outlines the specific solutions proposed.
Preparing For CTD Success
Authors: Ross M. , McLaughlin S. , Milne J. , Diller C. , English C. , Harris R.
Published: March 2015

CTD (Coil Tubing Drilling) has become a mature and successful technology in the continued development of the northern Alaska oilfields. Driven by advancing existing product limits and embracing new technologies, this paper details the development of a new completion technology that allows the operator to plan for and place pre-determined casing exit points within the wellbore to be accessed in the future as the well matures. This new technology addresses many of the typical limiting factors faced by operators when identifying future CTD candidates by reducing the typical preparation time, costs, and equipment limitations currently available to them.

The paper will show the viability and flexibility the operator gains by incorporating the use of pre-determined and spaced outer wedge assemblies affixed to the outside of the production tubing joints and run during the completion phase. The operator has the flexibility to run as many outer wedge assemblies as needed, based on their future field development strategy without imposing limitations on primary completion access or drainage capabilities. When required, an inner wedge assembly is then run and positioned within the outer wedge assembly, using a common wireline set tubing plug as a false bottom no-go. Orientation of the inner wedge is at the operators' discretion. The milling assembly will first mill through the production tubing before being deflected by the outer wedge assembly to then mill through the production casing. Details of the design, testing, and implementation of the system and components will be detailed within the paper.

This technology allows operators to plan for the life of the well at the completion phase. This reduces CTD preparation costs, provides simplified zonal isolation flexibility, and allows upper zones to be exited first if required. The technology reduces the risks and cost of dual string exits, while removing the need to leave an exposed large bore casing/liner at the exit point that could create difficulties during CTD drilling. Future advances and optimization of completion designs are expected to provide a cementless CTD liner completion while retaining zonal isolation capabilities within the wellbore.
MIC Related Coil Tubing Failures and Equipment Damage
Authors: Sherman Scott , Brownlee Duane , Kakadjian Sarkis
Published: March 2015

Microbial influenced corrosion (MIC) has been implicated in few corrosion-related challenges in the well service industry in the past. Recently, the industry is observing an influx of MIC-related equipment damage. This upsurge of MIC conincides with a switch to unconventional water sources. As fresh water for fracturing operations and well interventions becomes less available, operators are forced to use alternative water sources such as recycled flow-back water, produced water, and even ‘grey water’ from wastewater treatment plants. In some instances, recycled water is sold from one operator to another for operations on other pads. Regardless of the water source for a particular well treatment operation, the same water-hauling equipment and tanks are used for successive hydraulic fracturing operations.

This ‘communal’ use of water hauling and temporary water storage equipment is an ideal situation for bacteria to move from one water repository to another. Even if the water source used to supply water for oilfield operations is free from harmful bacteria, it may still become contaminated - in transport or temporary storage vessels - before it is pumped downhole.

This paper is an overview of premature coil tubing and other well servicing equipment failures and pumping equipment damage that is related to MIC. Metallurgical, chemical and microbial analysis of the scale as well as representative water samples have been conducted to determine if the corrosion was the result of sulfur-reducing bacteria (SRB) or merely pitting common to oil field equipment from pumping hydrochloric acid and other corrosive fluids. This paper will explore the potential source(s) of the bacteria, the impact to the equipment that was exposed to the bacteria, as well as what is being done to mitigate the problem.
Challenging Conventional Fluid Practices for Coiled Tubing Drilling
Authors: Myatt James , Lynn Stephen , Craig Steven , Murphy Stuart , Correa Pedro , Padron Tomas
Published: March 2015

The Buda formation in Texas presents extreme challenges to prevent formation damage during drilling operations. After using many fluid selection variations, several operators have determined that under-balanced drilling with native crude is the most optimum method. The initial startup project for coiled tubing drilling (CTD) operations in this formation has been completed, with more activity to come. However, as the preferred recirculation of the native crude drilling fluid presents two major challenges. First, the formation is up to 2% sour, and the native crude is relatively volatile with a low flash point and high vapor pressure.

Recirculation of sour crude will lead to double-sided exposure of the coiled tubing, which historically has resulted in extremely short fatigue life. The use of active fluid property testing, in addition to scavengers and inhibitors with defined mitigation plans, reduces the risk to an acceptable level. Significant laboratory testing of the fluid properties as the material degrades with time, temperature, and mixing have been completed. Additional mitigation actions are utilized in conjunction with the laboratory results to further reduce the volatility properties. Internal technical and operational reviews, along with additional sourced subject matter expertise, have challenged existing safety, operational, and technical limits. Operational procedures have been continuously monitored and adjusted to compensate for the adverse dynamic wellbore conditions encountered during the campaign.

The discussions within this paper detail the background challenges, laboratory testing, operational/HSE planning and mitigation practices to allow operations to commence. Additionally, the paper covers operational results as the wells are drilled. These results may provide a basis for future operations utilizing extreme fluid conditions in other applications within the industry due to the economic benefits from native crude.
Optimizing Memory Multidetector Pulsed Neutron Logging in Slim Horizontal Coil Tubing Drilled Wells Using a Carrier Assembly
Authors: Cedillo Gerardo , Raeesi Behrooz , Zett Adrian , Itter David , Marouby Philippe , Yonghwee Kim , Chace David , Giordanelli Henry , Martinez Carolina
Published: March 2015

Coiled tubing drilling (CTD) technology has been widely adopted as a cost-effective re-entry strategy to sidetrack from the existing wellbores, and drill high angle/horizontal wells to maximize recovery from remaining oil columns in the Alaska Prudhoe Bay field. The oil rim in this giant field is overlain by a gas cap and has been producing for over 36 years by various recovery mechanisms such as gravity drainage, water flood and miscible injection and hence, holds a complex fluid distribution with locally variable oil-water and gas-oil contacts.

Determining current reservoir fluid contacts using multidetector pulse neutron logging (MDPNL) technology is a crucial component in the overall strategy to maximize production from each well and identify future drilling targets. This technology has been widely used in the industry for reservoir evaluation and surveillance in open- and cased-hole environments using conventional wireline techniques in standard borehole sizes. However, logging tool conveyance in CTD wells has been challenged due to small hole size and high angle/horizontal/U- shape wells.

An innovative deployment assembly was developed by BP Alaska and Baker Hughes to acquire pulsed neutron data while tripping out of the hole during the wellbore cleanout operation, eliminating the need for a dedicated logging run, which in turn, reduces rig time costs. This deployment assembly consists of a non-magnetic stainless steel carrier and a memory adaptor that is attached to the MDPNL tool. The carrier does not limit tripping operations or wellbore circulation, and requires no wireline for data acquisition.

Another major advantage of this assembly is the additional compressional strength provided to the tool, which reduces failure rates and provides a cost-effective well logging solution in highly deviated wells.

This paper presents case studies in which this coiled tubing logging technology was applied in the Alaska Prudhoe Bay field. Various aspects of the technology are discussed, including the memory-enabled, three-detector pulsed neutron tool and carrier assembly configuration. The paper also discusses identification of reservoir fluid contacts and other petrophysical properties using the nuclear attributes extracted from MDPNL data, which ultimately provides the critical information needed for optimal perforation strategy and maximize oil production in CTD wells.
The Challenge of Gaining Access to a Suspended HPHT Subsea Well Using Coiled Tubing to Complete Full Abandonment to Current Standards
Authors: Freeman Mickey , White John
Published: March 2015

This paper details a case history of a recent HPHT CT well intervention operation to gain access to a suspended subsea well, in order to finally abandon the well including wellhead removal from seabed. There was a need to mill out the shallow set environmental cement plug to allow section milling and cement plug setting on well that had been originally suspended in 1997. The absolute worst case predicted pressure trapped below the shallow set cement plug was 12,500psi. This paper will take the reader through the full life cycle of the CT well intervention project. Starting with the initial feasibility study that lead to the selection of CT as the most viable option, moving onto the two sets of trials on test wells verifying the milling parameters and BHA selection. There will then be details on the 15,000psi live well intervention landing string that had to be manufactured to act as a conduit for the milling operations and also having the capability to shear the 2″ QT1000 0.203″ CT. The paper covers a review of the actual versus planned operations and captures high level lessons that would benefit future similar operations. The requirement to enter old wells that have been previously suspended / abandoned to fully abandon to current standards is an area of increasing interest. The use of CT to re-enter a HPHT subsea well has proven its versatility in comparison to alternatives such as costly relief well or HP interface equipment to allow jack up operations that could facilitate a snubbing unit.
Is Well Clean Enough? A Fast Approach to Estimate Hole Cleaning for Directional Drilling
Authors: Zhang Feifei , Miska Stefan , Yu Mengjiao , Ozbayoglu Evren , Takach Nicholas , Osgouei Reza Ettehadi
Published: March 2015

In spite of many recent technology improvements in drilling, hole cleaning remains a significant challenge, especially in deviated and horizontal wells. Inadequate hole cleaning can lead to a series of problems such as stuck pipe, fractured formation, high drag and torque, premature bit wear, decreased ROP, logging, and casing and cementing difficulties.

Hole cleaning is a complex issue that is affected by many drilling parameters. The major approaches of hole cleaning evaluations include experimental correlations and mechanistic models. But these techniques frequently require complex computations or numerical iterations to get the solutions.

In this paper, a set of charts is developed to allow the drilling engineer to quickly estimate the cuttings volumetric concentration in the wellbore. From previous cuttings transport studies, we know that well inclination angle, drilling fluid velocity, fluid rheology, fluid density and drill pipe rotation have the most important effects on hole cleaning. These parameters are divided into several ranges based on their sensitivity to cuttings concentration in the wellbore. The charts are obtained by running a hole cleaning simulator, which is based on a large number of experimental and modeling studies of cuttings transport.

The results of the charts are verified by experimental data. The difference between the charts' prediction results and experimental data are within 20%. Instead of solving complex equations in cuttings transport models, drilling engineers are able to quickly estimate the cuttings volumetric concentration by looking up the charts and conducting very simple calculations. This paper is also helpful in guiding the driller to quickly choose proper operational parameters during drilling operations.
Surpassing the Challenges of CT Interventions in a Trilateral Extended Reach Well in the Arabian Gulf
Authors: Issa Faiz , Zorbalas Konstantinos , Pardo Rolando , Zavala Eduardo , Chrysovulou Christina
Published: March 2015

The oil industry in the UAE is striving to advance both onshore and offshore operations to address technological challenges that will allow for increased oil production in a safe and efficient manner. Offshore, artificial islands are being built for the purpose of accommodating up to 300 wellheads on a single island, with the wells themselves comprising multiple, extended-reach horizontal laterals. These ground breaking projects present new and exciting challenges for coiled tubing (CT) interventions, which require extensive planning and the use of innovative technologies.

Specific challenges were identified during the design phase of intervening on a trilateral, extended reach well and applying several technologies enabled us to overcome these challenges to allow successful execution of a stimulation treatment on the well. Techniques used included accessibility modelling and CT string selection to achieve maximum reach.

The methodology used and the testing conducted were designed to ensure that the multicomponent CT bottomhole assembly (BHA) allowed for selective engagement of each lateral and subsequent horizontal accessibility of each extended-reach lateral. Operations were performed in the context of the completion restrictions, diameter of the openhole and cased-hole laterals, and the requirement to pump large volume acid treatments. Each of these factors added a layer of complexity to the final CT BHA selection and setup, which had to operate within a limited range of activation pressures and rates.

Finally, the lessons learned during the execution phase have been captured and recommendations formulated for moving forward with CT intervention in similar types of multilateral and extended reach wells. These lessons contribute to subsequent studies of maximum reservoir contact wells and form the basis of future development and intervention plans for the offshore and islands projects in the UAE.
Successful Offshore Coiled tubing Well Intervention in Mega-Reach Wells in the Russian Caspian: A 4-Well Case Study
Authors: Burdin K. , Mazitov R. , Bravkov P. , Lobov M. , Kichigin A. , Stepanov V. , Eliseev D. , Zemchihin A. , Byakov A.
Published: March 2015

Korchagin oilfield is located in the northern part of the Caspian Sea. Drilled wells are mega-reach (MD/TVD ratio greater than 3.0) with measured total depth (MD) up to 23,622 ft [7,200 m] and vertical depth of only 5,118 ft [1,560 m]. This presented a great challenge for coiled tubing (CT) well intervention even with the help of state-of-the-art hydraulic tractors. Limited working area, weight restrictions, challenging well geometry, completion features and lack of experience in offshore CT operations in the North Caspian Sea, required complex pre-job activities to optimize job design, select proper downhole tools and prepare a robust layout plan. This paper will illustrate the project preparation challenges, on-the-job troubleshooting and workflow, supported by the well case studies and results from the first CT operation in Northern Caspian Offshore. Lessons learned from the project, where all defined objectives were achieved with zero HSE (health, safety and environment) incidents, were also captured to assist in future campaigns with similar operational environment.
Improving Well-Work Efficiency and Mitigating Risk Exposure by Utilizing Digital Slickline in the Kuparuk River Unit, North Slope, Alaska
Authors: Wiese T. , Yoakum V. , O'Dell B. , Loov R. , Milazzo B. , Nemec J.
Published: March 2015

With approximately 1,200 wells and 47 developed drill sites in the Kuparuk River unit (KRU), North Slope, Alaska, a variety of well intervention services are required to keep wells in safe operating condition. Historically, conventional slickline and electric line services have performed a large portion of the non-rig diagnostics and repairs. With slickline operations generally limited to mechanical interventions and electric line required for depth-critical logging operations, both services are commonly required to complete a given well-work program. Because the intervention units are a shared resource, and the well-work schedule is priority based, there are often delays between slickline operations and the electric line diagnostics that follow.

Digital slickline services are being used in the KRU to improve overall well-work efficiency by completing intervention programs without the need for separate slickline and electric line services. Digital slickline services are being used to mechanically prepare wells for diagnostics, perform logging operations that would normally require electric line, and ready wells for repair without the need of additional service units. The enhancements linked to incorporating real-time surface readout data while performing mechanical interventions has reduced uncertainty and provided information for effective workover decisions. Using digital slickline technology has also mitigated risk exposure, as fewer crew hours are spent traveling and handling surface equipment. Examples of intervention work that have been completed with digital slickline services in the KRU include setting retrievable tubing patches, well integrity diagnostics and conventional slickline operations. The operations in the KRU have provided lessons learned and an understanding of the challenges associated with the technology.
Fishing Coiled Tubing With Internal Weld Seams and Failed BPVs in a Live Well Environment Using Hydraulic Workover (HWO)
Authors: McDaniel Ralph
Published: March 2015

This paper examines techniques necessary to fish coiled tubing (CT) with internal weld seams in a live well environment without back pressure valves (BPVs) using a hydraulic workover unit (HWO). The challenges of placing barriers in internal seamed CT verses using the slip and shear method is addressed.

The discussed onshore operation was completed August 2013 in North America. Using the techniques described, a 14,000-ft (4267 m) 2-in. (50.8-mm) CT fish was successfully removed from a well with an average surface pressure of 5,500 psi. This was achieved by first opening the blind rams, snubbing in, and dressing off the CT fish. Next, the CT fish was latched with an overshot and a pull test was performed, pressure was equalized, and the slip and pipe rams were opened. Following, the CT fish was picked up and moved to a desired location in the blowout preventer (BOP) stack (approximately 51 ft 4 in.). The slip rams were then closed and a weight check was performed. The pipe rams and inverted rams were then closed. The CT fish was shear/cut, the pipe was picked up and the blind rams were closed. This was concluded by laying down the fish and the process was repeated 276 times with an average cut of 50 ft. The HWO fishing procedures consisted of 541 hours without any health, safety, or environment (HSE) incidents, accidents, injuries, or job failures.
Coiled Tubing Completes Unique High-Pressure Well Abandonments in Remote Alaska Field
Authors: Webb Brendon , Cahill Peter , Broady Chad , Williams Paul , Greene Tim , Penrose Bill
Published: March 2015

Coiled tubing (CT) has been used in Alaska for over 20 yr as a low-cost alternative to a workover rig to complete a variety of well interventions in Arctic conditions in an effort to increase oil production. The majority of these operations are performed on wells that have a maximum anticipated surface pressure (MASP) that does not exceed 5,000 psi and are considered low-pressure wells. The working pressure of the lowest-rated component in the well control stack, including the operator's wellhead, is typically 5,000 psi. Therefore, CT interventions in Alaska on wells where the MASP exceeds 5,000 psi must be well planned far in advance of the job date to ensure that a thorough review of the equipment requirements, job design, and other aspects of the job are completed so that the operation can be executed safely.

Given current Alaska Oil & Gas Conservation Commission (AOGCC) regulations, an operator decided to re-enter five wells in the remote Point Thomson field area that contain hydrocarbons such as diesel or “arctic pack” (gelled diesel) in the wellbore to remove the hydrocarbon fluids and plug and abandon (P&A) the wells. There were several key challenges associated with this operation; these included the well's high MASP (7,900 psi), low ambient temperatures (−50°F), performing CT milling operations in large casing (9 5/8 in.), and cement placement through CT in zones with very low bottomhole temperature (29°F). The low-temperature cement system used was designed so that volumes of cement in excess of 200 bbl could be placed in the well through CT. In addition, a pressure and fluid management system for controlling pressure and removing solids and gas from the working fluids was used to manage high well pressures and reduce fluid costs. CT operations were completed safely. The application of CT to meet the requirements of these unique well abandonments allowed the operator to complete the P&A of all five wells.
Degradable Alternative to Risky Mill-Out Operations in Plug and Perf
Authors: Aviles I. , Dardis M , Jacob G.
Published: March 2015

With hundreds of thousands of well stages completed in 2014, the “plug and perf” technique is the number one stimulation method used in unconventional reservoirs. This technique relies on the use of metal or composite plugs to isolate sections of the reservoir to be hydraulically fractured. After all the stimulation operations are complete, plug removal is required to enable production to begin. A motor and a mill assembly must be conveyed into the well, usually by coiled tubing, to eliminate the plugs used during the stimulation.

In wells with low reservoir pressure or long horizontal sections, plug mill-out can prove very challenging. Returns do not easily reach the surface, and fluid is often lost into the recently created fractures. Even with the use of nitrogen to assist with cleaning operations, debris from the plugs removed can accumulate in the horizontal section, posing a risk of getting the coiled tubing stuck during the operation. In addition to this significant risk, the economic impact of such operations increases under these conditions because operations tend to be lengthier and more complex than traditional plug mill-outs.

A new plug-and-perf technology has been developed to address the problems mentioned above. This method relies on degradable technology to eliminate the need to remove plugs. During fracturing, this new technology follows the same process as traditional plug and perf, but no plug removal is required after stimulation. Seat assemblies serve the function of plugs, and after all stages are completed, these seats remove themselves by simple contact with flowback water. Immediate production is possible, and the well is left with a fullbore ID. No restrictions are left in the well that would prove problematic during any future workover intervention. This restriction-free environment also allows for the full production potential of the well to be achieved, as no chokes to production are left in the well.

The operational sequence of the new fully degradable isolation assembly for plug and perforate technique have shown a seamsless integration into current best practices for Eagleford operatiors, where the technology has been applied.
Optimization of Fuel Consumption in Compressor Stations
Authors: Elshiekh T. M.
Published: March 2015

Natural gas passing through pipelines is transported by means of compressor stations that are installed in pipeline-network systems. These stations are usually installed at intervals greater than 60 miles to overcome pressure loss, and typically, they consume approximately 3 to 5% of the transported gas, making the problem of how to optimally operate the compressors driving the gas in a pipeline network important. The objective function of the optimization model is a nonlinear mathematical relationship. The model has been studied to minimize the fuel consumption in the compressor stations and to obtain suitable decision-making variables. Genetic algorithms are used as the optimization methodology, and the software program Lingo (Thompson 2011) is used to compare the optimization results. Two cases of centrifugal compressor stations with different performances are studied. The optimization model aims to improve the fuel consumption of the compressor stations in the pipeline network according to the conditions of the transmissions.
Dynamic Plastic Deformation of Deepwater Steel Catenary Risers Under Extreme Cyclic Compressive Loading
Authors: Hu Guanyu , Campbell Mike , Huang Chaojun
Published: March 2015

Steel catenary risers (SCRs) on a large-heave-motion vessel are susceptible to compression in the riser touchdown zone (TDZ). Dynamic compression can lead to overstress under extreme or abnormal weather conditions. The response of an SCR under compression is highly nonlinear and sensitive to various factors. However, the current available industry design codes and practices do not provide a clear guidance to address the acceptability of compression, overstress, and the resulting plastic strains. In addition, the current analysis method used in industry common practice cannot capture accurately the nonlinear behavior of an SCR involving accumulated plastic deformation, hysteresis effects, and local buckling. In this paper, a finite-element-analysis modeling method that uses combined beam and solid elements is presented. This method enables simulation of large plastic deformation, pipe ovality, and local pipe buckling in the TDZ of a deeppwater SCR. The model is developed with Abaqus (Dassault Systèmes 2009). The SCR nonlinear response is examined through dynamic analysis of a deepwater SCR that is hung from a semisubmersible. The key analysis results are compared with a nonlinear beam-element model. Moreover, dynamic-ratcheting analysis under multiple plastic-strain cycles by use of the proposed solid-riser model is conducted to understand the plastic-strain accumulation and to check the acceptability of the survival response of a deepwater SCR under a series of sever hurricanes in its service life. This paper presents the methodology for evaluating the compression and plastic deformation that could be experienced by deepwater SCRs, including the modeling approach, analysis results, possible failure modes, and conclusions. The impact of the study findings on the robustness and suitability of SCRs for deepwater application is discussed.
The importance of corporate taxation for FDI attractiveness of southeast European countries
Authors: Kersan-Skabic Ines
Published: March 2015

The aim of this paper is to research the determinants of FDI inflows in the
SEE region with a special emphasis on corporate tax rates. The panel data
analysis (GMM methodology) was conducted on six countries in the period
2000-2011 in two versions: as gravity model based on bilateral FDI inflows
and on the total FDI inflows (and inward stock). The results pointed the most
important determinants for attracting FDI in SEE countries are market size
(population), growth rates, GDP per capita, and wages. Institutional
variables and corporate tax rates were not significant in the analysis of
flows, but they become significant in the analysis of FDI inward stock.
Perspectives of Taiwanese Pastoral Counselors on the Use of Scripture and Prayer in the Counseling Process
Authors: Der Pan Peter Jen , Deng Liang-Yu F. , Tsai Shiou Ling , Yuan S. S. Jenny
Published: March 2015

Interviews were carried out with 10 Christian pastoral counselors to explore their perspectives on the use of Scripture and prayer in the counseling process. Grounded Theory was utilized. Five main categories including a theological framework of pastoral counseling, counselors' considerations of using Scripture and prayer, preparation for Christian spiritual intervention, implications of spiritual resources, and ethical issues in the pastoral counseling process were generated. The results suggest the theological framework of pastoral counseling is crucial to the use of Scripture and prayer, and the issue of a neutral response should first be clarified for clients. Basic guidelines for ethically using Scripture and prayer for working with Christian clients are proposed for further pastoral counselor training, practice, and research.