bluuebunny/crossref_metadata_2025_split huggingface dataset:
Combining Elastic and Plastic Fatigue Damage in Coiled Tubing
Authors: Bridge C. D 
Published: September 2011

Abstract
Coiled tubing is a continuous pipe that, having been coiled around a reel for storage, can be deployed and used as a pipeline or riser. During deployment as a riser, the coiled tubing is unspooled from the reel, run into the water and connected to the wellhead. This process plastically strains the pipe causing plastic, or low cycle, fatigue damage. When the coiled tubing is connected to the wellhead, the environmental loading causes elastic stress cycles, resulting in elastic, or high cycle, fatigue damage.
There are numerous methods to determine the fatigue life from either plastic or elastic cycling; however, there is little data within the industry on how the fatigue damage from elastic and plastic cycles combine.
This paper presents the experimental work conducted to show the combined fatigue life of coiled tubing that has been plastically and elastically cycled. The data shows that the combined fatigue life can be lower than the summation of the plastic and elastic fatigue damages using Miner's rule. Existing theory suggests that the combined fatigue life could be as low as 10% of the Miner's rule of fatigue damages; however, the experimental data indicates that a more appropriate value is closer to 75% of the Miner's rule fatigue damage.
Operational Benefits of Coiled Tubing Enabled with New Real-Time Data Communication System
Authors: Taggart Michael , Murray Niall , Sturgeon Trevor 
Published: September 2011

Abstract
A recently developed system enabling real-time data to be transmitted from intelligent downhole tools to surface recording and display equipment has been in use for over 12 months. This system is engineered so that there is negligible impact on conventional Coiled Tubing operations. Coiled Tubing weights and surface pump pressures are almost unaffected by the presence of this system and ball operated tools can be operated with confidence.
The primary purpose of the system is to allow accurate control of the position of the BHA, previously not achievable with conventional coiled tubing. Trials using this new system have been completed. In addition to confirming the operational ability of the system, the data-stream revealed previously unrecognised information. The benefit of this additional information will enhance the operational success of many coiled tubing operations.
Field operations completed with the system to date, have demonstrated the benefits of a system transmitting downhole information while completing a wellbore intervention. The operations discussed show the advantages of a system that allows accurate depth control while maintaining the functionality of coiled tubing, such as ability to circulate fluids through the coiled tubing and function ball operated tools.
This paper describes the system components, injection equipment and discusses the findings revealed during system trials. Many operations with the system have been completed since introduction and operational and benefits confirmed during these operations are outlined. Operations involving the use of logging tools have been completed and have proven the advantages of the system, with combining the abilities of conventional coiled tubing with real-time coiled tubing logging operations.
Best Practices for Multizone Stimulation Using Composite Plugs
Authors: Lehr D. J. , Cramer D. D. 
Published: September 2011

Abstract
Treatment isolation using composite bridge plugs (CP) has been practiced for about 18 years in North America and continues to be among the most economical ways to stimulate horizontal and multi-layer vertical wells. Despite this long experience, many end users still experience problems in these applications because of sub-optimal choices regarding product selection, run-in and removal options, and unrealistic expectations regarding plug life in downhole environments.
This paper will identify best practices for using CPs, based on prior technical papers, field experience, and manufacturers' published data. These practices maximize the chances of successfully installing and removing CPs in multi-zone treatment applications, improving the economics of oil and gas plays requiring multiple stimulation treatments per well.
As multi-zone completion activity increases in regions outside of North America, treatment applications using CPs will also increase in those regions. Realizing the benefits of using CPs in emerging regions will be achieved by learning about best practices from regions with extensive experience in their use.
New Hybrid System Brings the Flexibility of Coiled Tubing to Long, Extended-Reach Wells
Authors: McNeil F. , Lindsay S. D. , Lyons R. , Gracey R. P. 
Published: September 2011

Abstract
The number of long, extended-reach wells being drilled in the oil and gas industry continues to increase. These wells present complex challenges in completion and intervention procedures because operators demand the same level of performance achieved on shallower wells while providing a cost-effective and safe solution.
To reach deep target depths with coiled tubing (CT), smaller coil must be used because of reel capacity, which limits pumping rates because of pressure and velocity limitations. Many areas have road weight restrictions that will also dictate the size and length of CT that can be used. As an alternative, jointed pipe can be used; however, using jointed pipe reduces the overall efficiency of the process, as continuous pumping cannot be achieved.
The new hybrid system uses both CT and jointed pipe in a single workstring. The system incorporates a unique flapper safety valve that enables seamless functioning of the string in a live well. The hybrid system enables larger CT and jointed pipe to be deployed, which results in higher pumping rates and depths. This reduces the overall job time, while improving safety and efficiency for deeper well applications, including multizone stimulation, cleanouts, drilling, and mill-outs.
This paper presents the hybrid system design and benefits in multizone stimulation, drillouts, cleanouts, and other well-intervention applications. Also included is a case history to demonstrate the success of the system when applied in a multizone fracture-stimulation treatment.
Accurate Downhole-Temperature Estimates are Critical to Proper Slurry Design-Improved Data-Collection Method Field Tested Successfully
Authors: Velazquez F. Santillan , Arias R. Aguilar , Castro J.. , Cerón F. Evar , Rogers H.. 
Published: September 2011

Abstract
Temperature is a parameter of great importance when simulating and modeling cementing or temperature-activated fluids (McSpadden and Glover 2008) because it affects the amount of retarders or accelerators needed to avoid undesired phenomena, such as premature cement setting or incomplete consolidation of the treatments. In 1964, API introduced the first set of tables (API 2005) that listed the circulating temperatures and hydrostatic pressures for certain wellbore circumstances and bottomhole conditions and the fluids that could be used in different well treatments, such as cementing, lost-circulation control, and water or gas control, etc. The API procedures have been widely adopted and recognized in the oil industry, and most operating companies feel comfortable using them. However, increased demand for oil and gas has forced operators to perform drilling, completion, and maintenance operations in deeper and more complicated zones. These zones are often classified as high-pressure/high-temperature (HPHT) fields.
Currently, combining computational tools, such as computer simulation software and measurement sensors, allows operators to accurately measure temperature and pressure values and adjust them with well-known heat-transfer models; as a result, possible temperature changes during complex operations can be more accurately modeled. This paper presents multiple case histories showing the significance of using bottomhole pressure/temperature (P/T) measurement tools and the modified modeling of the heat-transfer effects as a function of operational parameters (flow rate, density, wellbore geometry). With more accurate temperature data, laboratory testing can be performed to better predict the behavior of the treatments mentioned when exposed to the more complex bottomhole conditions encountered.
Assessing Well Integrity Risk: A Qualitative Model
Authors: Dethlefs J. C. , Chastain B. 
Published: September 2011

Abstract
For successful delivery of Well Integrity, there needs to be an understanding of the risks that can cause undesirable events such as safety hazards or loss of containment. Performing a risk assessment on a well, or type of well, will help determine and rank the potential risks and provide information that allows limited resources to be applied in the most effective manner. The main objectives of performing a risk assessment include: Follow a formal process to assess risk consistently and to enable comparison between well barrier failure mode scenarios;Qualitatively assess well barrier failure risk for every segment of a well;Document suggestions that are offered by the risk assessment team for mitigating well barrier failure risk; andProvide a report of the methodology, failure mode scenarios, risk ranking, and potential mitigation actions for use as a reference tool for managing well integrity on a routine basis.
The Well Integrity Risk Assessment Model follows a common qualitative risk assessment process; a team-based, structured brainstorming format, utilizing the What-If Methodology, to identify potential hazards associated with well barrier failure modes. In addition, the model has the following attributes: Incorporates a unique method to segment well barriers into discrete sections, successively "failing" each section for evaluation. The list of analyzed well barrier failure modes, along with their risk ranking, becomes the risk register for the well or type of well.Is adaptable for assessing well barrier failure modes on a single well, or a group of wells, having the same general design parameters. An entire well portfolio can be assessed quickly by analyzing types of wells rather than individual wells.Can be used to assess well barrier failure risk for any type of well.The model can easily be modified to conform to any company's risk model.
The Well Integrity Risk Assessment Model has been proven to: Successfully assess well barrier failure risk for thousands of wells;Focus specifically on well barrier failure modes, and as a result is an effective tool that should be incorporated into a "Best in Class" Well Integrity Program;Be utilized as a management tool to provide guidance for how limited resources can be used effectively to continuously deliver well integrity.
Unified Reservoir / Well / Network Model for Advanced Processes
Authors: Moncorgé Arthur 
Published: September 2011

Abstract
A formulation for the fully coupled simulation of reservoir, well and network for advanced processes is described in this paper. The governing equations for the reservoir, well and network are generalized into the same finite volume framework. The approach is close to Shiralkar and Watts (SPE 93073) but it uses natural variables and is generalized to: (1) energy and aqueous components (polymers, surfactants, salts, …) conservation equations, (2) mass and energy accumulation terms in the wells and the network to simulate transient effects, (3) acceleration terms in the wellbore. The motivation of this work is to have a consistent formulation for the reservoir, the well and the network, allowing (1) no limitation in the well/network architecture, (2) ease of implementation and maintenance, (3) use of advanced linear solvers.
Negative Saturation Approach for Compositional Flow Simulations of Mixed CO2-Water Injection into Geothermal Reservoirs, Including Phase Transition and Disappearance
Authors: Salimi Hamidreza , Wolf Karl-Heinz , Bruining Johannes 
Published: September 2011

Abstract
Cold mixed CO2-water injection into hot-water reservoirs can be used for simultaneous geothermal-energy (heat) production and subsurface CO2 storage. This paper studies this process in a 2D geothermal reservoir for a homogeneous reservoir, a layered reservoir, and a heterogeneous reservoir represented by a stochastic-random field. We give a set of simulations for a variety of CO2-injection concentrations. In this process, often regions of two-phase flow are connected to regions of single- phase flow. Different systems of equations apply for single-phase and for two-phase regions. We develop a solution approach, called the non-isothermal negative saturation (NegSat) solution approach, to solve efficiently non-isothermal compositional flow problems (e.g., CO2-water injection into geothermal reservoirs) that involve phase disappearance, phase appearance, and phase transition. The advantage of the solution approach is that it circumvents using different equations for single-phase and two-phase regions and the ensuing unstable switching procedure. In the NegSat approach, a single-phase multi-component fluid is replaced by an equivalent fictitious two-phase fluid with specific properties. The equivalent properties are such that in the single-phase aqueous region, the extended saturation of a fictitious gas is negative.
We discuss the salient features of the simulations in detail. When two phases are present at the injection side, heterogeneity and layering lead to more CO2 storage compared to the homogeneous case because of trapping. In addition, layering avoids movement of the CO2 to the upper part of the reservoir and hence reduces the risk of leakage. Our results also show that heterogeneity and layering change the character of the solution in terms of useful-energy production and CO2 storage. The simulations can be used to construct a plot of the recuperated useful energy versus maximally stored CO2. Increasing the amount of CO2 in the injection mixture leads to bifurcation points at which the character of the solution in terms of energy production and CO2 storage changes. For overall injected CO2 mole fractions less than 0.04, the result with gravity is the same as the result without gravity. For larger overall injected CO2 mole fractions, however, the plot without gravity differs from the plot with gravity due to early breakthrough of a supercritical-CO2 tongue near the cap rock. Including gravity, we have a choice of optimal energy recovery 1273 TJ with a limited CO2 storage of maximal 2449 kton or minimal energy recovery of 437 TJ with maximal CO2 storage of 9388 kton.
Downhole Chemical Injection Through Gas Lift: Options and Consequences
Authors: Daas M. A. , Golczynski T. S. , Magalhães A. A. , Bastos E. C. , Ferreira P. A. 
Published: September 2011

Abstract
Gas lift is being utilized to enhance production of heavy crude from the Campos field offshore Brazil. Downhole chemical injection is implemented to treat the crude and assist with chemical inhibitor delivery to protect the reservoir fluids in the well tubing from corrosion due to elevated concentrations of hydrogen sulfide (H2S). Due to the absence of dedicated chemical injection lines in the field, H2S scavenger is diluted in ethanol and transported with the gas lift, through the gas lift line (GLL), to the well casing. The gas lift and aqueous chemical phase flow together in the inner annulus between the casing and tubing as a multiphase mixture. The mixture is then injected into the well tubing through a gas lift valve (GLV). Field measurements have shown the crude is not always uniformly treated with the chemicals due to unsteady discharge of the chemicals from the casing into the production tubing through the GLV.
Advanced steady state and transient simulations were carried out to analyze the supercritical / multiphase flow in the gas lift system. Moreover, the complex phenomena associated with the hydraulic instability upstream of the GLV, and subsequent irregular injection of the multiphase mixture into the tubing, were well-characterized.
Simulation results are qualitatively accurate and descriptive as they duplicate the phenomena observed in the field. It was found that the dynamic stability of the wellbore was disturbed by either insufficient pressure gradients at the GLV or by localized slugging initiated in the casing. As such, chemical accumulation in the casing and intermittent pressure build-up upstream of the GLV were responsible for the non-uniform injection into the well tubing. The system’s dynamic stability can be restored by either increasing the casing pressure to a level high enough so the GLV tolerates normal variations in the casing pressure or by manipulating the flow pattern in the casing to avoid slug flow. Simulation results proved both techniques to be effective.
Field data and simulation results show that GLL may be substituted for chemical injection lines provided the GLV is designed based on a sound understanding of the system’s hydraulics and a reasonable prediction of the operating pressures on its sides throughout the well life.
Findings from this study provide guidelines for proper flow assurance practice and safe design and operation in artificial gas lift and chemical injection applications
Inversion of Time-Lapse InSAR Data for Reservoir Pressure Monitoring: Example of the Krechba Field, Algeria
Authors: Lecampion B. , Cooksley G. , Loizzo M. , Arnaud A. , Robles J. Garcia , Zhang Z. , Sheng X. 
Published: September 2011

Abstract
Time-lapse lapse interferometric synthetic aperture radar (InSAR) images provide accurate surface deformation over a large area and are sensitive to fluid injection/production at industrial scale. The quality and quantities of surface deformation time series open new opportunities for reservoir management. In this paper, we investigate the resolution of pore pressure change from InSAR highlighting some intrinsic features of such type of measurements (i.e. loss of resolution with distance to source). Depending on the relative ratio of the reservoir depth over the source lenghtscales (e.g. reservoir extent), we propose two new robust inversion schemes consistently tackling the issue of loss of resolution without additional information: i) multipole moment decomposition for far-field case and ii) decomposition of the pore-pressure field change via Chebyshev series truncated at the order governed by the expected resolution.
The example of the Krechba field illustrates our discussion. In particular, we show, using a far-field decomposition that the center of the pressure source remains in the reservoir layer around the KB501 injector and we recover quantitatively the direction of the flow anisotropy. We also discuss the direct inversion of the pore-pressure changes via Chebyshev decomposition. The requirement of a fast but accurate enough geomechanical model is emphasized in order to integrate time-lapse InSAR images with other conventional measurements for history matching purposes.
Innovative Pattern Balancing and Waterflood Optimization of a Super Giant Carbonate Mauddud Reservoir, Raudhatain Field, North Kuwait
Authors: Al-Ajmi Moudi , El-Daoushy Ahmed , Ashkanani Fatma , Saleh Iskandar , Pathak Ashok , Hamadi Hajer 
Published: September 2011

Abstract
Raudhatain-Mauddud, a super-giant depletion-drive oil reservoir in North-Kuwait, is undergoing massive development efforts, with a planned enhancement in oil production through phased pattern-waterflood. The Phase1-development covers the crestal-area of the structure, which is the focus for current development efforts through 8 inverted 9-spot patterns. This poster outlines the successful integration of a lot of team's collaboration to significantly improve the operating procedure for water flooding. This effort required a new way of managing this reservoir: a comprehensive approach of balancing voidage with injection, conducting extensive surveillance/analysis to assess the efficacy of various courses of action and, most significantly, adjusting various teams' "key performance indicators" to align injection and production allowable with sound reservoir management principles.
An innovative unified information management system was used to monitor voidage replacement ratio (VRR) to provide a basis for pattern balancing. A very extensive surveillance operation provides the data necessary to monitor individual pattern balance and water cut performance, optimizes areal sweep efficiency by adjusting injection and production allowable, assist in planning water-shutoff operations, and design new completions.
Time lapsed monitoring and the surveillance data indicates the reservoir is relatively well connected. However, after applying the new management approach, individual waterflood pattern balance is significantly improved and the field-wide VRR is around 1.2.
All of these activities have led to the enhanced understanding of the waterflood behavior and the model updates. Sound reservoir surveillance and waterflood management procedures implemented within a diverse group of teams that have performance goals aligned with "best practice" has resulted in effectively re-balancing this major waterflood.
A Novel Approach for Breakout Zone Identification in Tight Gas Shale
Authors: Soroush Hamed , Qutob Hani , Rasouli Vamegh , Tokhmechi Behzad 
Published: September 2011

Abstract
The decline of production of conventional reservoirs and increase in demand of hydrocarbon fuels bring the tight gas into the forefront of the energy future. This unconventional energy source is a fast-growing market and is recognised as having huge future potential for production worldwide. Low permeability of tight gas shale requires conducting effective hydraulic fracturing and applying horizontal drilling technologies to produce at commercial level. Therefore, successful production from such complex reservoirs is heavily dependent on the selection of an appropriate completion technology requiring sufficient knowledge of borehole shape. Therefore, understanding the rock properties and the earth’s stresses (Geomechanical Model) is the first critical step in reservoir evaluation and ultimately development of these resources. In order to determine in-situ stress condition and calibrate geomechanical models, having information of borehole breakouts existence plays a key role.
Caliper and image logs, the regularly used methods to identify breakout zones, have several limitations such as not having a full coverage of the borehole wall, being affected by different parameters, pad width limitation, low resolution, and complicated processing procedure. In addition, good quality image logs are not usually available for shaly formations because of the requirement of using oil-based mud.
This paper presents a new multi-variant approach to identify borehole breakouts in tight gas shale using some petrophysical logs. This approach employs number of data processing techniques, including Bayesian classification, wavelet decomposition and data fusion, to determine borehole intervals with maximum likelihood of enlargement. The results approved the applicability and the generalization capability of the approach with a significant accuracy. Case study on Burnett shale is presented in this paper.