bluuebunny/crossref_metadata_2025_split huggingface dataset:
CT-Deployed Multipurpose Nozzle for Effective Sand-Cleanout and Acidizing Operations in a Single Trip: Injector Wells Case Histories
Authors: Uchendu C. V. , Awoleke O. O. , Rowland S. P. , Ndinemenu F. O. 
Published: December 2007

Abstract
Wells requiring combined sand clean out and acidizing operations have been routinely treated using BHA's containing different nozzles in multiple trip operations. This is especially true for sanded-up completions. The normal scenario would be to use a standard wash nozzle for both acidizing/sand cleanout operations or to use a switchable nozzle for the sand clean-out, POOH and then run a rotating jetting nozzle (for acidizing). Ho wever, the former scenario would not be optimal because standard washing nozzles are not effective against filter cakes / scale and the latter alternative might be in some situations an over-kill leading to really expensive operations.
This paper describes the use of a specialized nozzle that generates a ‘vortex’ or a fast swirling mass of fluid in the completion tubulars/open hole. Jet velocities and rotational speeds commonly exceed 460 ft/sec and 8000 rpm, respectively. Because of a specially designed internal flow guide, this nozzle entrains debris and also provides improved jet coherence and projection compared to standard jetting nozzles. This dual feature of the nozzle made it particularly attractive for use in combined sand clean out/acidizing operations of sanded up injectors. This nozzle also has no moving parts or rubber seals; therefore, the commingling fluid phases would not affects the efficiency of the tool.
These injectors are vertical completions with architecture ranging from perforated intervals to standalone screens. The sediments consist of a mixture of organic deposition, fine siliceous material and carbonate scales. This paper analyzes the improved post injectivity and compares results using this nozzle to those using a wash nozzle/rotating nozzle combination on the basis of cost, operational efficiency/simplicity and technical effectiveness. These results suggest that some non-aggressive scales can also be treated using this nozzle as an alternative to a rotating jetting system leading to reduction in well intervention cost through a single trip approach.
Vortex-Induced Vibration of Tubings and Pipings with Nonlinear Geometry
Authors: Adnan S. , Chen Y. , Chen C. L. P. 
Published: December 2007

Abstract
Vortex-induced vibration (VIV) of tubings and pipings is of practical interest to oil industry. When VIV occurs to pipes, it induces alternative stress that results in the reduction of pipe fatigue life. The objective of the paper is to investigate VIVs in tubings or pipings with non-linear geometry.
This paper categorizes the occurrence of cross-flow and in-line VIVs of pipes based on flow directions and pipe orientations. The complexity of VIV for pipes with non-linear geometry, as compared to straight pipes, is demonstrated. We devised a scheme to incorporate power balance principal into finite element method (FEM) to analyze the cross-flow VIV for tubings and pipings with non-linear geometry. A main feature in our approach is the modeling of lifting forces (excitations) and hydrodynamic damping in FEM. At present stage, most commercial VIV packages mainly deal with risers or pipelines that are either straight or with large radii, and they only considered curvature component associated with the cross-flow direction of the flow (d.o.f.), that is the direction perpendicular to the flow velocity. Stress calculation near the bends and elbows of the pipes, is not accurate. Our approaches, on the other hand, consider the responses in all 6 d.o.f of each element along the pipes and it is a truly three dimensional vibration analysis. Our approach provides an alternative to complement the existing method for solving the VIV problem for tubings and pipings with highly non-linear geometry.
Dynamic Upscaling From a Complex Triple-Porosity System to a Single-Porosity Model: A Successful Application for a Miscible-Gas-Injection Project
Authors: Tealdi L. , Giordano D. , Nembrini E. , Cappanera F. , Francia L. 
Published: December 2007

AbstractDual porosity numerical models are widely adopted in the oil business to model the performance of complex systems characterised by two different porous media. However, for numerical models of a certain complexity due to the large number of active grid-blocks, the dual porosity approach is often computationally unaffordable especially when a compositional formulation must be used.This paper describes the methodology that was developed to mimic the dynamic performance of a complex triple porosity system by means of a single porosity model. The three porous systems were the matrix blocks, the fracture network and the dissolution karst bodies. The methodology was derived for a complex massive carbonate field not yet producing which is currently envisaged to be developed via miscible gas injection.The matrix and karst bodies were statically modelled independently from the fracture network system. The characterisation of the fracture network has been driven using a DFN approach by integrating seismic, continuity cube interpretations and well data, such as FMI and mud losses. Due to the lack of dynamic data, the fractures' petrophysical properties were calculated from correlations. The matrix, karst bodies and DFN derived fractures were then up-scaled to a dual porosity model. The dual porosity model dynamic performance was considered as the reference to be matched by an equivalent up-scaled single porosity model.An innovative procedure to up-scale matrix, fracture and karst properties into the equivalent single porosity model was tested for both a natural depletion and a miscible gas injection scenario. The methodology was firstly evaluated in representative sector models and then extended to the full field model. This methodology resulted to be very efficient being able to reduce the simulation time and model complexity drastically while capturing all the dynamic key performance indicators of the more complex and computationally expensive dual porosity model.
Influence of Prior Cycling on Fatigue Damage Caused by Defects in Coiled Tubing
Authors: Tipton S. M. , Neuharth L. G. , Sorem J. R. 
Published: December 2007

Abstract
Fatigue is known to be a major factor limiting the useful life of coiled tubing in the field and the presence of a defect is known to accelerate the onset of fatigue. Research efforts are underway to study the influence of defects such as scratches, dents, gouges, and other geometric discontinuities. The majority of this research has been conducted by placing defects in new tubing samples and cycling to failure. However, tubing in the field often incurs mechanical defects later in life, after fatigue damage has already accumulated due to prior cycling of the tubing in a defect-free state. This paper presents results from a quantitative investigation of the influence of varying amounts of cumulative damage from prior cycling on the detrimental effect of a defect. Coiled tubing with yield strengths of 90 and 110 ksi are used in the experiments and defects consist of transverse cuts made with a hack saw blade. The data indicate that prior cycling can influence the rate of damage accumulation caused by a defect, but this dependence appears to be dependent on the internal pressure level, which was held constant during these tests. The application of a simple Miner’s rule makes conservative estimates of fatigue lives for tubing cycled with low internal pressure, but estimates can be nonconservative for higher pressure levels.
Overview of the Kuparuk CTD Program and Recent Record-Setting Operations
Authors: Venhaus D. E. , Blount C. G. , Dowell K. E. , Gantt L. L. , Sarber J. G. , Worthington A. J. , Rixse M. G. 
Published: December 2007

Abstract
The Kuparuk Coiled Tubing Drilling (CTD) program began with the development of dynamically overbalanced CTD techniques1 in 1998. Although many of the first wells were technical successes, the economic and productive results were less than expected.
Starting with a step change in 2002, improvements in the economic results of the CTD program have materialized over the past 3 years fueling excitement about CTD in the Kuparuk River Unit (KRU). Results from the 11 well 2005 CTD program suggests that the successful application of CTD technology will continue in the Greater Kuparuk Area (Fig. 1).
Technological advances, changes in target focus, improved well designs, improved CT drilling techniques, and persistence all paid off. The 2004 & 2005 CTD programs delivered wells yielding rates beyond expectations and, in the case of 2005, were achieved "at or below" the authorized expenditure budget. In addition to the overall CTD program success story, what the authors believe as 3 new world records were set on one particular well: Deepest 3" CTD sidetrack – 18,350’ MD; deepest CTD openhole sidetrack – 17,935’ MD; and deepest CTD liner run – 18,320’ MD. All drilling objectives were achieved and the well completed under the AFE (Authorization for Expenditure).
Integration of a Risk-Management Tool and an Analytical Simulator for Assisted Decision-Making in IOR
Authors: Alvarado V. , Reich E. -M. , Yi Y. , Postsch K. 
Published: December 2007

Abstract
Risk management has become an integral part of the decision-making workflow in the oil and gas upstream business. As many oil fields reach a mature state, the need for rejuvenation and decline mitigation of assets set ground for Improved-Oil Recovery (IOR) opportunities. However, the associated decision-making process requires incorporating screening, reservoir simulation and financial evaluation, demanding complex multidisciplinary team efforts. It is important that any stage of the analysis, technical, strategic and economically sound decisions should be made.
On one hand, IOR screening, whether based on technical grounds or ‘gut feeling’ experience, or better yet on both criteria, leaves a number of possible IOR processes available for evaluation through simulation. Analytical simulation and applicability screening tools are often favored on early stages. However, their crude application could mislead the decision process if results are not carefully interpreted and combined with reservoir engineering expertise and additional evaluation criteria.
We propose to combine IOR screening strategies with spatial reservoir information to help to create appropriate sector models as starting point for more detailed evaluations. For this purpose, we couple an analytical simulator/IOR screening tool with a software tool that aids framing the IOR decision-making problem effectively, in the form of influence diagrams. From these diagrams, it is possible to create Tornado Diagrams, Decision Trees and Monte Carlo profiles that assist Reservoir Engineers with the task of properly and rationally framing the decision process, for example with regard to economic risk assessment and NPV analysis associated with IOR.
The coupling between both software solutions is proposed in a way that avoids the inflexible monolithic constructions. We illustrate advantages of the proposed approach through a speedy analysis of a publicly available case.
Risk Analysis With History Matching Using Experimental Design or Artificial Neural Networks
Authors: Reis L. C. 
Published: December 2007

AbstractOil companies have increasingly adopted Risk Analysis in decision-making processes. Most risks are related to reservoir uncertainties. Risk Analysis, even combining possible values of the input parameters (uncertainty variables) in the flow simulations, can create unrealistic models and compute wrong results (decision variable). Some reservoirs have dynamic data that can reasonably constrain the model increasing the Risk Analysis confidence.Three methodologies based on Experimental Design and Response Surface Modeling (RSM) to model flow simulations are proposed. In the first method, one RSM is built to model the decision variable and another RSM is built to represent an Objective Function that takes into account dynamic data. Then, a relationship among the uncertainty variables obtained from the RSM of the Objective Function is applied to the RSM of the decision variable to constrain the model, enabling the Risk Analysis with History Match. In the second methodology, a maximum tolerance of the Objective Function is used as a filter to select the models taken on Risk Analysis. The third method is similar to the second one, but Artificial Neural Network replaces RSM to model the flow simulation. Even though requiring more simulation runs, such approach seems to be skillful to deal with non-linearities.The methodologies were applied to two different reservoirs in Campos Basin, Brazil: a semi-synthetic case where dynamic data were simulated to represent the behavior of an appraisal phase field and a real case where the reservoir produces for more than five years. Significant reduction on the decision variable uncertainty is observed showing the importance of constraining the models when dynamic data are available.The methods show that it is possible to improve the quality of the Risk Analysis, constraining the possible range of the uncertainty variables by taking into account dynamic data.
A Practical Approach in Building Upscaled Simulation Model for a Large Middle East Carbonate Reservoir Having Long Production History
Authors: Nair C. V. G. , Al-Maraghi E. 
Published: December 2007

Abstract
A comprehensive reservoir model that provides excellent turnaround time for historymatch and evaluation of different development scenarios had been developed through careful application of upscaling methods for the large carbonate reservoir of Umm Gudair field located inKuwait and partitionedneutral zone. The model was built maintaining integrity of the geological model.
The detailed geologic model, built using the latest techniques, was very large (157 layers, 10 million cells) and itwas necessary to upscale the model into a reasonably sized simulation model thatruns smoothly witha good turnaround timetomakemultiple runs tomatch 42 years oil/water productionand pressure history ofabout 200 wells. The vertical upscaling were to bedone maintaining the integrity of the fine-scale geological model, preserving physics of the displacement process and providing provisions for water shut off jobs implemented through squeezing off bottom perforations.
Although the flux-basedupscaling techniques provided guidance, it alone was not sufficient to optimize the layering scheme for the simulation model. A hybrid approach combining the elements of the methods of minimizing variation and flux, manual judgment and streamline simulation was applied to generate a vertically upscaled model with 42 layers that effectively replicated the fine-scale fluid flow behavior. Two simulation modelswere generatedwith different arealdimensions - a coarse modelwith 200×200 mt (to accelerate the history match process) and a fine-scale model with 100×100 mt (983,000 active cells) for infill drilling studies. Excellent history match has been achievedand the model has been demonstrated as an effective reservoir management tool for further field development.
This paper discusses the steps applied towards effectively converting the geologic model to simulation model through upscaling, the systematic approach towards buildingthe history match model highlighting the critical steps and an overview of the quality ofhistory match.
Suplacu de Barcau Field—A Case History of a Successfull In-Situ Combustion Exploitation
Authors: Panait-Patica A. , Serban D. , Ilie N. 
Published: December 2007

Abstract
This paper describes the thermal recovery implementation used on the Suplacu de Barcău field, from the beginning of the production life until 2005. The field is a heavy oil, near surface Pliocene clastic reservoir, situated in the north-western part of Romania, in the Pannonian Depression.
Drilling operations, beginning in 1956, revealed a heavy and viscous oil reservoir. In 1961 a few wells were put into production, as part of an in-situ combustion (ISC) test. Between 1960 and 1970, an important number of wells established the structure and reservoir parameters, from which an original oil in place volume was calculated.
In order to confirm the theoretical model of high efficiency, related to thermal recovery methods, steam drive (SD) and in-situ combustion (ISC) were concurrently tested during the period 1963-1970. The better performance of ISC during this semi-commercial stage led to the decision in 1970 to design the entire reservoir exploitation using this method. The ISC exploitation has been successfully developed and improved in time, becoming the largest of this type in the world and is one of the most important fields exploited by Petrom.
There are now nearly 800 wells with a total production of about 1200 tones/day of crude oil (2005). The cumulative extracted crude in 35 years is about 17,8 million tones, which corresponds to a current recovery factor of 44,6%.
This paper presents the most significant highlights of this field exploitation, including the challenges encountered, the surveillance methods, as well as the important lessons which have been drawn from the exploitation of this field.
The Development of a Revolutionary Scale-Control Product for the Control of Near-Well Bore Sulfate Scale within Production Wells by the Treatment of Injection Seawater
Authors: Collins I. R. , Duncum S. D. , Jordan M. M. , Feasey N. D 
Published: December 2007

Abstract
The formation of sulfate scales arising from the injection of seawater into hydrocarbon-bearing formations for pressure maintenance and secondary oil recovery has been a significant problem in many onshore/offshore operations. To address this, batch scale inhibitor squeeze treatments, scale removal, and modification of the injection brine (sulfate removal, produced water injection, aquifer water injection) have been applied with varying degrees of success. The development of deepwater projects, where conventional scale control technology may be uneconomic for the control of mineral scale, has required a re-evaluation of the methods of scale inhibitor deployment.
For the past five years, BP Exploration has been developing a novel approach to the application of scale inhibitors with the objective of eliminating the requirement for both active scale inhibitor squeezing and scale removal operations. This has been achieved by the development of nano-sized, controlled release, solid scale inhibitor particles that can be added to the injection water such that the particles pass through the formation and release the scale inhibitor into the fluids near the production wells.
The principle of solid particle transport in porous media is demonstrated using core flooding tests and reservoir modelling. This confirms that solid particle transport is possible and that minimum retardation relative to the injected brine can be achieved. Static and dynamic release characteristics of the scale inhibitor formulations evaluated to date will be presented. The factors to be considered in the commercial manufacture and initial field trial results will also be presented together with the economic justification for this type of scale control process.
This technology offers a revolutionary scale control process that could eliminate the need for sulfate-reduction plants whilst still providing effective scale control within the reservoir and near-wellbore region for deep water developments.
PDOB's Proactive Approach to Solving a Zonal Isolation Challenge in Harweel HP Wells Using Swell Packers
Authors: Laws M. S. , Fraser J. E. , Soek H. F. , Carter N. 
Published: December 2007

Abstract
The Harweel Cluster in Southern Oman is PDO’s first EOR Project. It is being developed in a phased manner using miscible gas injection. Reservoir simulations have been carried out to show that a significant increase in ultimate recovery can be achieved by successfully isolating gas (and water) if it breaks through prematurely to producing wells. In order for the additional reserves to be obtained, zonal isolation is required over the reservoir section. To date, isolation has proved to be inadequate using conventional cementing technology and techniques.
A trial was therefore carried out to determine the effectiveness of using oil swellable elastomers ("Swell Packers") to achieve zonal isolation. Three swell packers were run in a well and tests were devised to determine the success of the elastomers following expansion.
Based on the results, zonal isolation was achieved as indicated by a combination of selective perforating, wireline logging and production testing. This is the first time that zonal isolation has been observed in these challenging, HP, sour wells.
Application of Engineered Cementing Solution to Solve Long-Term Cement Integrity Issues in Tunisia
Authors: Krusche K. , Johnson C. R. , Braud N. Y. , Ghazi H. B. 
Published: December 2007

Abstract
An operator faced a recurring problem of early cement-casing/cement-formation microannulus development followed by interzonal communication. In some cases, this unwanted communication led to the complete loss of production, resulting in a drastic loss of revenue. The loss of production was attributed to water-cut levels up to 78%. At this point, the operator was no longer willing to risk another massive loss, so a step-change decision was made to cure the problem at the source; hence, it was necessary to devise a solution to eliminate this detrimental effect in future well production.
Due to well events, which induced downhole pressure and temperature changes, additional stress was imposed on the cement sheath. An example of a temperature decrease was swapping drilling mud with colder brine prior to running the completion. This systematically caused contraction across the production interval, resulting in development of a microannulus on both sides of the cement sheath.
Computerized stress simulations indicated the presence of a microannulus, which compromised hydraulic isolation across the pay zone. This was also evident in previous wells in this field. The operator felt that requiring an engineered solution would maintain long-term zonal isolation.
This paper describes a case history covering the challenge faced by a North African operator, the development of an engineered solution, and the field execution of the job. The success of applying cementing technology will also be shown through cement bond log response. In addition to the successful step-by-step approach adopted by the operator, the results have allowed further work to be performed with other operators in Tunisia who face similar challenges.