bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Static Friction in Coiled Tubing HPHT Operations Using Real-Time Data
Authors: Pittman I. , Christie M. P. 
Published: December 2007

Abstract
Coiled tubing (CT) is being pushed to the limits of its capability by the more complex and challenging nature of wells currently being drilled. Either the yield limits are being approached because of the extremely deep high pressure, high temperature (HPHT) wells, even with the use of 100,000-psi strength CT, or the reach capability is being surpassed by the long step out of horizontal wells. To accurately predict the results of such an intervention, the planning phase must include detailed modeling combined with previous experience.
This paper will describe the theoretical effect that static friction would have on CT well interventions and compare this with the actual values found through the analysis of data recorded real time on the same wells. Static friction will be quantified in a number of HPHT wells and the resulting effect on the force required to pull out of hole will be presented. Testing performed to evaluate the static friction through the stripper will also be presented. These values will be used to help ensure the CT well bore friction is accurately quantified.
High Pressure High Temperature Coiled Tubing Intervention Operations in the North Sea Within the Past Two Years
Authors: Turner A. , Murdoch B. 
Published: December 2007

Abstract
High Pressure High Temperature (HPHT) fields in the North Sea continue to both push, and ultimately extend, the boundaries of what can be safely and successfully achieved through intervention with coiled tubing (CT). Within the last six years successful CT deployed perforating operations have become relatively common. However, as more and more HPHT fields consider intervention operations, existing technologies are subsequently examined and re-examined to suit the particular well criteria and also the actual operating environment of the particular offshore installation.
This paper begins by discussing the types of equipment that are required for HPHT CT intervention. It then presents a number of recent case histories concerning CT interventions on HPHT fields. Three of these case histories involve different underbalance perforating operations. Case histories concerning cementing operations through CT are also discussed. The paper outlines the specific types of downhole equipment that are needed for these operations. This includes application of new equipment designs and novel solutions to both surface and downhole constraints.
Lessons learned from each of the case histories will be presented together with an overview of the requirement that HPHT fields and the related CT intervention technologies are moving towards. Conclusions will be drawn from these different case histories and a discussion presented on the potential extension for CT intervention in HPHT environments.
Simulation of Inflow whilst Underbalanced Drilling (UBD) with Automatic Identification of Formation Parameters and Assessment of Uncertainty
Authors: Friedel T. , Mtchedlishvili G. , Voigt H.-D. , Häfner F. 
Published: December 2007

Abstract
Underbalanced drilling (UBD) is defined as a drilling operation where the pressure of the circulating drilling fluid is lower than the pore pressure of the target formation of interest. The most widely recognised benefit of UBD is the reduction of formation damage by minimising the drilling fluid leakoff and fines migration into the formation. It also facilitates the possibility for reservoir characterisation during drilling. The purpose of this paper is to present (i) how to use the inflow data for the evaluation of formation properties and (ii) how to cope with the uncertainty of the results.
An in-house multiphase reservoir simulator is used for the simulation of the formation reservoir fluid flow during UBD. The model incorporates discrete consideration of the well with appropriate, time varying UBD boundary conditions. Capillary forces, which facilitate countercurrent imbibition of the drilling mud into the formation, are taken into account.
The production rates during UBD depend on the formation properties and the drilling conditions. The inflow information is analogue to transient test data and can be used for the estimation of the reservoir model parameters. With the advancing of the drilling process, the amount of available inflow data increases and allows for a sequential history match procedure. Based on a statistical analysis of the inverse problem we identify the optimal level of parameterisation as quality and quantity of the measured data justifies.
Technical contributions of this paper include (i) the usage of a reservoir simulator to derive the inflow of fluids in heterogeneous reservoirs and (ii) its coupling with gradient- based optimisation techniques for determination of certain reservoir parameters. The "simulation while drilling" approach proposed is fully automated and can set-up on a known or totally unknown reservoir model, introducing an iterative and automatic updating process of the reservoir model.
Development of a Thermodynamic Model and Reservoir Simulator for the CH4, CO2, and CH4-CO2 Gas Hydrate System
Authors: Zhu T. , McGrail B. P. , Kulkarni A. S. , White M. D. , Phale H. , Ogbe D. 
Published: December 2007

Abstract
An equation of state (EOS) software module was developed for CH4, CO2, and CH4-CO2 mixed hydrates by using VanderWall-Platteeuw model. The model is based on classical thermodynamics and is used to predict the thermodynamic behavior of gas hydrates including pressure and temperature at which gas hydrates form. A numerical scheme was developed for solving Lw-V-H and I-V-H equilibrium conditions for bulk hydrate formation from pure water and gas. The model was further extended to determine hydrate equilibrium conditions in the presence of salt. The results calculated from the model were in close agreement with the experimental data reported in literature. One of the contributions of this work is that the proposed model can predict hydrate dissociation pressures at temperatures above 285 K more accurately than any of the existing available modules. The new EOS has been implemented in the multiphase flow simulator STOMP-CO2 developed at PNNL for simulating geological storage of carbon dioxide. Simple reservoir simulations were performed with the new module to examine decomposition of methane hydrate and formation of CO2-hydrate as a new means of natural gas production from gas hydrate reservoirs.
Numerical Modeling of Sand Production Mechanisms with Displacement Discontinuity Method
Authors: Lavrov A. , Cerasi P. , Papamichos E. 
Published: December 2007

Abstract
Sand production mechanisms were numerically studied by means of a displacement discontinuity boundary-element method. The method allows an explicit modelling of fracture growth in rocks in 2D. Rock fracture in hollow cylinder sand production tests was simulated. Different types of fracture growth typically observed in hollow cylinder tests were investigated, i.e. breakout formation, slit propagation and uniform collapse of the cavity. Changing the mechanical behavior of the rock, represented by the properties and constitutive behavior of the displacement discontinuity elements, from brittle to ductile resulted in a change of the failure pattern from breakouts to uniform collapse, reproducing thus the laboratory tests. A clear effect of the specimen size (external diameter) on the results was demonstrated numerically. The increase of the external diameter of the hollow cylinder results in a virtually linear increase of the hollow cylinder strength, at least in the range of diameter values investigated.
Inverted Hockey Stick Method Reveals Greater Uncertainty in Petroleum Investment Evaluations
Authors: Olsen G. T. , McVay D. A. , Lee W. J. 
Published: December 2007

Abstract
Conventional oil price forecasting methods in the petroleum industry typically consider uncertainty by incorporating optimistic, pessimistic, and most-likely cases. Commonly, these price projections are "hockey stick" forecasts, i.e., forecasts that are initially flat or decline for some period of time and then increase monotonically. Review of historical forecasts by industry and governmental organizations show that conventional forecasting methods often fail to capture the true uncertainty associated with oil and gas prices. Performing discounted cash flow calculations using conventional oil and gas price forecasts will therefore underestimate the uncertainty associated with project economic performance indicators. Akilu et al. developed the Inverted Hockey Stick (IHS) Method to address these shortcomings. This new method for quantifying the uncertainty of price forecasts honors the historical extremes of oil and gas prices (on a constant dollar basis) along with the maximum positive and negative historical rates of change. To investigate the uncertainty associated with economic indicators (e.g., net present value, investment efficiency, and internal rate of return), we applied the IHS method to 23 completed or proposed projects from 12 operators. We found the P50 IHS value for these economic indicators is comparable to the most-likely value from conventional price forecasts. Across all 23 cases, however, the IHS method predicted a wider range of economic indicator values than conventional forecasts. The IHS method may be preferable over conventional methods due to its ability to quantify more realistic upside and/or downside risk associated with projects in the upstream petroleum industry.
Cementing a Long Horizontal Wellbore Using CT Squeeze Technology
Authors: Rauchenstein W. , Blount C. G. 
Published: December 2007

Abstract
Coiled Tubing (CT) cementing has been widely used and highly successful for remedial squeeze and plug back operations for over 20 year's1,2,3. However, the vast majority of these wells were at deviations less than 90 degrees.
A long horizontal well in the Alpine field on the North Slope of Alaska was drilled early in the development phase and was out of pattern (Fig. 1). The well required a plug back and sidetracking to maintain desired off-take strategy (Fig. 2). The well was drilled to a total depth of 11,984 feet and completed with approximately 2,050 feet of 4-1/2" slotted liner inside the 2,210’ of 6-1/8" hole. Near the middle of the horizontal section, the well's deviation climbed to a maximum of 96 degrees.
Cementing operations have long been recognized as a problem in horizontal wells. However, a search of the SPE online library identified only 5 papers that mentioned the challenge we faced while a search of "horizontal" yielded 5,534 hits. Although the 5 papers did discuss the problem and gave some general guidance to cement design consideration, there was little specific information on the "best practice" approach to Plug and Abandon (P&A) long horizontal wellbores.
Based on the successful CT squeeze program in Alaska, a team of engineers and field supervisors decided to use CT cement squeeze technology to seal the lateral portion of the wellbore and leave a cement base for subsequent sidetracking operations. This paper will discuss the details of this job including: Job PlanningCement design and testingTools and EquipmentWellbore geometry and Placement detailsOnsite Job Execution detailsResultsLessons learned
Hydraulic Fracture Monitoring as a Tool to Improve Reservoir Management
Authors: Peterman F. , McCarley D. L. , Tanner K. V. , Le Calvez J. H. , Grant W. D. , Hals C. F. , Bennett L. , Palacio J. C. 
Published: December 2007

Abstract
We present the results of a multi-stage hydraulic fracture monitoring campaign performed during 2004 on one of Dominion Exploration and Production, Inc. producing well in the mature tight gas Sawyer field, Sutton County, Texas. The purpose of these microseismic monitoring surveys was to determine the overall geometry of the hydraulically induced fractures in the Canyon Sand formation. Information and results derived from the microseismic interpretation were used to provide the operator with recommendations for reservoir management (e.g., drilling patterns, new well placement, completion practices, etc.)
An initial borehole seismic survey confirmed optimum tool positioning to accommodate background noise and acoustic coupling. Additionally, calibration of sonic velocities was performed. All these factors led to an unprecedented level of understanding of the treated formations. All available pieces of information pertaining to the monitoring and treatment wells were combined to give a calibrated velocity model, which lead to the accurate processing of the microseismic data acquired during the one-day long hydraulic fracture operation.
The stimulation treatments utilized a titanate fracturing fluid system assisted with carbon dioxide. All six stages, except one that was surface pressure limited, were successfully placed with very little or no adjustment to the treatment design. All imaged fracture systems were oriented along the same azimuth. Larger than anticipated fracture heights were generated, and the acoustically-defined effective lateral extent of the various fracture systems was less than anticipated. Higher than designed fracture heights illustrate that it may be beneficial prior to the next design to measure specific formation mechanical parameters (e.g., in-situ stress, Young's modulus, Poisson's ratio, etc.) for simulation purposes. To minimize height development, fracturing fluids exhibiting lower fluid viscosity, injection rate adjustments, etc. have been recommended. Imaged fracture systems, all oriented along the same azimuth, suggested that present drilling pattern was inadequate for optimum drainage. Therefore, new locations for increased density drilling have been decided. Such wells are currently being drilled.
To further complement the added value of the information obtained with this data, we are performing a prorated production analysis. This will help determining effective permeability, effective fracture half-length, fracture conductivity, and skin damage factors. As well as it will allow the design, execution and evaluation cycle to be complete and provide us with lessons learned and best practices to implement in upcoming wells and operations.
Fluid-Flow Phenomena in CT Using CFD
Authors: Rosine R. , Bailey M. , Blanco I. 
Published: December 2007

Abstract
Coiled tubing (CT) is widely used in well intervention as a practical and cost-effective means of servicing wells. Over the years, the actual flow through CT has been a point of discussion and theory. Testing has been conducted to promote a better understanding of what happens inside the CT. In recent years, the use of computational fluid dynamics (CFD) software has provided greater insight into actual CT flow patterns, including fluid-flow velocity profiles and secondary flow regimes. These flow patterns can be studied in a straight pipe or curved (CT) condition with variable flow rates and variable fluids. CFD could help us understand the phenomenon of erosion, including particle path and migration through the tubing. It might also lead to a greater understanding and efficient design of friction pressure gradients. After CFD is proven and established, an alternative to full-scale testing or other predictive methods may be possible.
This paper discusses the flow phenomenon of CT using CFD, particularly over the tubing guide. This is an area of concern because the tubing configuration changes from straight to bent to straight again. Details of fluid flow for both the straight and curved sections have been examined to evaluate flow-velocity profiles and flow patterns. Fluids investigated have included water, gel, and slurry.
Some New Developments Applicable to Coiled Tubulars
Authors: Stanley R. K. 
Published: December 2007

Abstract
Complacency has little place in coiled tubulars. Here we describe the new techniques that are under investigation for both CT inspection and seamless CT production. The possibility exists to make tubulars by cold compression and to join by microwave sintering methods and amorphous bonding. The probability now exists to monitor all joining processes via the nondestructive acoustic emission technique, advanced ultrasound, and to eliminate the conventional tube-to-tube butt weld.
Environmental Assessment After Decommissioning at the Offshore North Sea - Frøy Oil Production Site: A New Field Proven Methodology
Authors: Plisson-Sauné S. , Beyer J. , Moltu U. E. , Pinturier L. , Sundt R. , Berland H. , Bjørnstad A. 
Published: December 2007

Abstract
The oil production at the Frøy field in the North Sea (Norwegian Continental Shelf) ceased in 2001 and the platform was removed the year after. As a supplement to the regular sediment monitoring program, an extended assessment of the "environmental condition" at Frøy has been conducted in June 2003 using biological effect parameters.
Emphasis was given on effects of drill cuttings contaminated by chemicals some of which possibly contained poly aromatic hydrocarbons.
The paper describes the operational methodology used and its cost efficiency. It also describes the know-how and the improvements gained during the field survey.
The results, presented in the paper, show the operational feasibility and the advantages of this new methodology which takes into account the effect of drilling wastes not only on sediment communities but also on other animals (fish, shrimps, etc.). They also demonstrate the absence of adverse effect of the remaining piles on the area and consequently prove that the site was released in good environmental condition for all compartments of the marine environment.
Estimation of Long Term Gas Condensate Well Productivity Using Pressure Transient Data
Authors: Osorio R. , Stewart G. , Danesh A. , Therani D. , Jamiolahmady M. 
Published: December 2007

Abstract
Conventional composite models can be used to calculate gas condensate well skin values including that due to condensate banking. However, the calculated skin varies in time as the fluid properties and gas and condensate fractional flow change, hence, making estimation of long term performance of a well unreliable. The dependency of gas and condensate mobility on the flow rate at near well bore conditions makes the problem more challenging. We have addressed this issue by developing an analytical method to use transient well test data to determine gas-condensate relative permeability, accounting for the rate effect, which makes future performance prediction a more reliable task.
Synthetic well test data have been generated by a commercial compositional numerical simulator with and without the rate effect. The impact of including the rate effect in the simulated cases on well test analysis results has been evaluated. The results show that for the cases analysed that the derivative of pressure responses does not necessarily always exhibit a three-radial composite behaviour due to condensate banking, when the rate effect is present, though such behaviour could be exhibited in some cases.
Our developed analytical methodology is based on a technique that allows estimating the reservoir pressure as a function of distance from the well, at the end of the drawdown period, using the bottom-hole pressure value before the shut-in. Once this reservoir pressure profile is available, the actual reservoir pressure gradient as a function of distance is determined, which can be used to calculate the values of gas and condensate relative permeability. Therefore, we show for the first time that it is possible to calculate from pressure transient data the near well gas and oil relative permeability values accounting for the rate effect. The well must be shut in at the bottom of the hole to avoid any wellbore storage effect on pressure build-up. We also show that the size of the two-phase region can be predicted with excellent accuracy using an analytical approach.
Multidisciplinary Workflow for Oil Fields Reservoir Studies - Case History: Meleiha Field in Western Desert, Egypt
Authors: Campobasso S. , Gavana A. , Bellentani G. , Pentoli I. , Pontiggia M. , Villani L. , Abdelsamad T. H. 
Published: December 2007

Abstract
Coping with mature fields located in lithologically complex formations is a difficult task. The large amount of data and information acquired during the field history requires a tight cooperation between different disciplines to pursue the objective of the reservoir study in the most effective manner. A typical result of this work is the development of new integrated tools to:
handle and integrate different types of geological data help in solving the history match problems define the optimum locations for infilling wells derive reliable production forecast cases
This paper illustrates the Case History of Meleiha Field, where team work and new technologies were applied aiming to support an intense infilling campaign through a reliable simulation of the fluids flow in the reservoir and to predict future field behaviour in terms of oil rate, water cut, GOR and pressure.
Meleiha Field, located in the Western Egyptian Desert, consists of four pools with five oil-bearing intervals in the lithologically complex Bahariya Formation, lying at a depth of some 5000 ft TVDSS and characterized by thin intercalations of sands, glauconitic sands, cemented sands, shales and carbonates.
Production commenced in December 1984, with artificial lift well completions; oil recovery was initially via natural depletion and then enhanced through water injection.
The integration of petrophysical facies characterization and sedimentological model with a suitable geostatistical approach allowed to create a black-oil simulation model of these highly heterogeneous and complex reservoirs in order to achieve a reasonable history match.
Finally, the use of an optimization tool supported the selection of about 40 development wells locations.
Following the study indications, 10 wells have been already drilled with encouraging results both in terms of prognosis confirmation and, most important, of additional production.
Coiled Tubing Conveyed Fracturing System Allows Longer Zones to be Isolated in a Single Trip Multiple Times
Authors: Stricker M. P. , Romano F. J. , Plante M. E. , Holmes B. 
Published: December 2007

Abstract
Increased production and lower costs in shallow gas wells are closely linked to developing and refining new coiled-tubing drilling, completion, and production techniques. Innovations in coiled tubing have reduced the costs of drilling and completing these wells and increased their productivity and life cycles. Coiled-tubing fracturing is one such innovation. This has been used for some time now, predominantly in North American shallow gas wells. In these wells, the cost advantages associated with working over the well in a live condition while reducing job time are attractive.
Coiled-tubing fracturing operations usually employ straddle-type tool configurations. However, with a typical maximum lubricator length of about 30 ft, straddle interval lengths have been restricted, which increases the amount of resets required to effectively fracture individual zones. This restriction also increases the potential risk of communication above the assembly.
This paper describes the development of an economical and reliable coiled-tubing fracturing system that allows selective fracturing of previously bypassed pay zones. This is now possible because the system can be conveyed in a tandem configuration that works within current lubricator restrictions, but is capable of setting repeatedly as a retrievable bridge plug and treating packer combination. This allows longer zones to be precisely isolated multiple times in a single trip in hole.
This innovative technique can not only reduce intervention costs but also reduce the total time required to complete the operation. This paper will examine several case histories, with emphasis on pre-job planning, equipment selection, well site execution and post-job results.