bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling Well Performance Under Nonequilibrium Deposition Conditions
Authors: Civan Faruk 
Published: December 2007

Abstract
A nonequilibrium well productivity decline model is developed and solved analytically under the same simplifying conditions of the previous equilibrium models. The solution is compared with the analytical solutions of the equilibrium models. It is demonstrated that deposition for nonequilibrium flow conditions is less compared to equilibrium flow conditions. Charts are developed and presented for the productivity index and skin factor in terms of relevant dimensionless parameters. In addition, the formulae for estimation of the radius of the plugging region (skin radius), and the producing time required for partial plugging of the formation at various percentages of the initial porosity and the time for complete plugging of the formation are derived. Numerical examples are presented, illustrating the applications of the formulations, and the predictability of the productivity decline of wells. The new improved model alleviates the limitations of the previous equilibrium models and more accurately predicts the productivity decline. This model can be used for determination of the rate of productivity decline by scale formation, the skin radius, and hence the well inflow performance and for scheduling of the treatments necessary for effective well stimulation.
Total Downstroke Friction From Downhole Dynamometer Analysis
Authors: Long Scott W. , Smith Elton J. , Mehaffey Kirk , Garza Albert S. 
Published: December 2007

Abstract
The oil and gas industry is benefitting from development and use of improved predictive computer programs that now utilize several friction defaults.
These predictive programs are more capable of predicting surface and downhole rod pumping conditions. The need for improved predictive accuracy is requiring program users to adopt improved estimates of downstroke friction to model downhole pumping conditions. Lack of improved estimates of downstroke friction has resulted in program users accepting and designing with current friction defaults. Use of these defaults may culminate with results not representative of actual downhole pumping conditions.
This paper develops a method of estimating total downstroke friction from existing dynamometer analysis. Use of this method in producing fields with similar operating conditions will provide improved estimates of total downstroke friction.
A better understanding of the magnitude of total downstroke friction will result in improved friction defaults. Improved friction defaults will result in more effective designs of rodstrings and artificial lift systems.
The Impact of Non-Darcy Flow on Production from Hydraulically Fractured Gas Wells
Authors: Handren Patrick , Pearson C. Mark , Kullman John , Coleman Robert J. , Foreman Jay , Froebel Keith , Caron Jon 
Published: December 2007

Abstract
The pressure drop due to flow within a propped fracture results from three mechanisms: viscous drag of the fluid, inertial effects associated with the movement of fluid around the proppant grains, and multiphase effects associated with the interaction of the different fluid phases.
Most existing fracture models and production simulators analyze the effects of viscous drag only, often underestimating the total pressure drop in the fracture by one or two orders of magnitude. These models rely solely on the reference permeability of the proppant, which is measured in the laboratory with extremely low flow rates of 2 to 10 cc/min. This paper reviews the design changes necessary to accommodate the incremental pressure losses resulting from multiphase and non-Darcy flow, and shows application of the theory to two operators' stimulation programs.
Production rate projections and economic analyses are provided for fracture treatments conducted in two field programs (both gas reservoirs): Total-Fina-Elf's development in the Frio and Vicksburg reservoirs of South Texas and Chevron USA's Birch Creek Unit in the Green River Basin of Wyoming.
Fracture treatments in existing wells had been designed with traditional Darcy flow models. New stimulation treatments were redesigned to include multiphase and non-Darcy flow effects. This paper provides details of the two different stimulation treatment designs in each of the development programs and the production results – average productivity increases of 20 to 30% for the new wells compared to offset wells treated with stimulations based on Darcy flow design models.
Experimental and Mathematical Modeling of Wax Deposition and Propagation in Pipes Transporting Crude Oil
Authors: Nazar A. R. Solaimany , Dabir B. , Vaziri H. , Islam M. R. 
Published: December 2007

Abstract
One of the problems faced by the petroleum industry is the wax deposition in pipelines during transportation of waxy crude oil. Oil companies dealing with waxy crude often spend millions of dollars in remedial procedures. An ideal design should use an accurate mathematical model that would include all salient features of wax deposition and waxy crude transport to predict wax deposition during crude oil transportation. In this paper, a comprehensive mathematical model both in laminar and turbulent flow regimes is developed. The model couples energy equation with deposition and removal kinetics model and thermodynamic model.
The k-ε turbulent flow model and energy equation were used to predict velocity and temperature distributions in the turbulent flow regime. Molecular diffusion of wax, as a mechanism of deposition and sloughing effect due to the hydrodynamic forces of fluid on deposited wax, have been considered. Parametric studies on the variation of the amount of wax deposition were performed for a mixture of toluene and oil wax cut in an experimental setup. Overall predictive ability of the proposed model is excellent for the laminar flow. For the turbulent flow regime, no necessary complete experimental data for model were available. Consequently, qualitative results were presented and discussed.
Safety Critical Learnings in Underbalanced Well Operations
Authors: Jansen Sjors , Brett Peter , Kohnert Jorg , Catchpole Roger 
Published: December 2007

Abstract
This paper describes Shell U.K. Exploration and Production's (Shell Expro) approach to managing safety critical activities when bringing onshore underbalanced drilling techniques into an offshore North Sea environment.
Prior to 1996 underbalanced drilling (UBD), including low or reduced head had never been carried out, offshore, in the North Sea. However, sound economic justification provided the impetus to introduce this technique and associated technology. There were many significant safety challenges that had to be addressed to demonstrate that the risks were within the limits of tolerability and as low as is reasonably practical (ALARP). The primary HS&E concerns related to: loss of containment (continuous pressure at surface), competence of personnel (UBD differs from conventional drilling operations) and safely designing, installing and operating the new technology required for offshore UBD activities. While UBD had been successfully carried out in many onshore environments it was recognised that this experience did not readily translate to an offshore North Sea environment. Consequently, much of the technique and technology had to be revisited to provide the project team with the necessary level of assurance required to confidently proceed with underbalanced operations. Since 1996, the Shell Expro UBD Project Team has successfully implemented underbalanced drilling; this paper illustrates some of the main HSE issues that need to be managed for UBD operations.
Deepwater Drilling with Lightweight Fluids - Essential Equipment Required
Authors: Hannegan D. M. , Bourgoyne A. T. 
Published: December 2007

Abstract
New equipment described in this paper has been developed for employing underbalanced drilling techniques on a floating drilling rig. Field trials of this equipment are being conducted on a semi-submersible vessel in the Albacora Field of the Campos Basin located offshore Brazil. The test is being conducted in a partially depleted formation with a pore pressure equivalent to approximately 7 lb/gal. The formation will be drilled slightly overbalanced during the test.
Unplanned Disconnects in Deepwater Drilling: Prevention Measures and Emergency Response
Authors: Bruce D. , Foster D. , James R. , Plaisance M. , Kropla S. , Nelson C. 
Published: December 2007

Abstract
In 2000, two unplanned disconnects of the Lower Marine Riser Package (LMRP) occurred on deepwater rigs in the Gulf of Mexico. Both were attributed to human error. The IADC Deepwater Well Control Task Force reconvened to study this problem and investigate preventative measures. The results of this study were presented to the Minerals Management Service (MMS) in July 2000. The report includes recommendations regarding the Primary Control System for prevention of unplanned disconnects as well as guidelines concerning backup systems to maintain or regain wellbore security. The backup systems studied include 1) intervention by Remote Operated Vehicle (ROV); 2) deadman systems/autoshear systems; and 3) acoustic control systems.
Off Setting Kill and Choke Lines Friction Losses, A New Method for Deep Water Well Control
Authors: Botrel Thierry , Isambourg Patrick 
Published: December 2007

Abstract
Deepwater well control with a subsea BOP is often difficult and in many circumstances impossible with the usual methods and procedures. This is not only due to the narrow margin between pore and formation fracture pressures, but also to friction losses in kill and choke lines. Such a situation is aggravated by the sharp rheology increase experienced with synthetic or oil base mud that is caused by the low temperatures deep sea. In some field cases, the gelling effect of mud at low temperature even preclude to start circulating out the kick without exceeding the formation fracture pressure. By injecting base oil or primary emulsion at BOP level, mud hydrostatic, rheology and gelling effect can be significantly lowered. These enable one to compensate for friction losses and to circulate out the kick at a higher flow rate. Kick control through kill and choke lines may be attempted when it is impossible with usual procedures. Computed simulations of this new kick control method applied to some real field cases demonstrate benefits of the method. The decrease of the mud rheology due to the mixture with base oil or primary emulsion is quantified by rheological measurements.
Designing Underbalanced Thru Tubing Drilling Operations
Authors: Nas S. , Laird A. 
Published: December 2007

Abstract
This paper describes the planning issues that will need to be addressed when planning underbalanced thru tubing drilling operations.
Planning a conventional underbalanced well can be complicated at the best of times. Planning a thru tubing underbalanced operation is even more complicated. For a successful thru tubing operation, a significant amount of planning and experience is needed. Very often we see that the service providers for coil or UBD services get asked to help in the planning aspects of a well. Although their experience in executing operations associated with their equipment is significant, planning a thru tubing (TTD) well with the objectives of an operator in mind is not their daily business. We have seen a number of operational failures either as a result of poor planning or as a lack of experience. Many of these failures are being blamed on the equipment or on the technology as many operators are unaware of the current limits of TTD operations. This is partly due to the fact that many thru tubing drilled wells are experimental technology projects with operators testing if thru tubing operations can be executed on their own wells.
It has been proven in Alaska and Oman that a sustained campaign of thru tubing underbalanced drilling can lead to significant cost savings and operational improvements. Yet in many area's of the world, both underbalanced drilling technology and thru tubing drilling technology is not implemented due to uncertainties on the successful outcome of a TTD project. Experience in the planning and operational aspects of a TTD-UBD well is extremely important to achieve a successful outcome.
Continuous Depth-Indexed Analysis of Production-Log Data in Oil-Water Flow
Authors: Hoadley S. F. , Kabir C. S. , Kamal D. 
Published: December 2007

Abstract
Production logs (PL) are traditionally interpreted by collecting depth-indexed information recorded by four major sensors; that is, pressure, temperature, density, and flow velocity. Although foot-by-foot data are gathered during flowing and shut-in passes, flow interpretation is normally done over selected discrete depth intervals, known as stations.
This study explores data analysis on a continuous depth basis rather than that done at discrete stations. In so doing, we obtain unbiased in-situ flowmeter calibration, leading to improved understanding of wellbore flow behavior and production log interpretation.
Global Virtual Teamwork Cracks The Athel
Authors: Bell Matt , Alixant Jean-Louis , Smits Wouter G. , Turner Bob , Maas Jos G. , Ruijtenberg Piet , Hoogeveen Wouter 
Published: December 2007

Abstract
In 1997, Petroleum Development Oman (PDO) assembled a team of experienced engineers to tackle the unique challenges presented by the Athel play. These deep, high pressure, sour oil accumulations found in the South Oman salt basin were known to contain substantial oil in place but were considered sub-economic due to poor productivity resulting from extremely low permeability. The team sought to better understand both the reservoir and its dynamic behaviour, in search of cost-effective development options.
By early 2000 the Athel team had completed three years of focused research and development activities during which time the team evolved into one of the pioneering global teams in the EP sector - the Athel Global Virtual Team (GVT) - calling on a multitude of world-wide resources (both internal and external), managed by an integrated team from PDO and Shell E&P Technology and Research (SepTAR).
Visible progress in 1997 and early 1998 contributed significantly to shareholder confidence in approving a green-field Phase 1 development of the Al Noor reservoir. This has culminated in a fast-track project delivering first oil on 12th August 2000, 30 months after approval. The team has addressed all of the objectives laid down in 1997 and has routinely exceeded project targets.
This paper examines the challenges faced by the team and the evolution of its global virtual structure. Factors contributing to their success are identified and conclusions and key learnings for future project teams are drawn.
Water and Gas Control Jobs in Indian Offshore Field (Bombay High) - Trends and Case Studies
Authors: Sinha G. K. , Sinha R. 
Published: December 2007

Abstract
Bombay high, an offshore oil field was discovered in the year 1974 and was put on production in May1976. Water injection in this field was started in 1984. The main pay zone L-III is of miocene age. L-III is a multilayered, anisotropic limestone reservoir with a gas cap and partial water drive. L-III reservoir of this has 13 different sub layers, which are separated by shale streaks.
Water Shut off jobs: Bombay high wells started producing water since 1984-85. Preferential depletion of high permeability layers in a set of high and low permeability layers perforated together and subsequent preferential flooding of these layers has led to an early break through of water as well as water loading of wells. This has also led to the leaving oil un-drained in less permeable layers. Earlier attempts to shut off water with conventional squeeze jobs met with a little success. However candidate selection with proper diagnostics and mechanical isolation of the squeezed layer has resulted in remarkable success. But this could not address to the middle water producing zones. In order to overcome the limitations of conventional cement squeeze jobs and in search of better success ratio on sustained basis and with the advent of various gel–chemicals, a number of gels of reputed companies were used during 1993-97 for water shut off jobs. However the results were not encouraging either. Recently during 1999-2000, extensive lab studies were done on cores simulated at reservoir conditions and the compatible gels were used. Three water shut off jobs have been done using these gels.
Gas shut off jobs: Success ratio remained low with the cement squeeze in between the oil producing and gas bearing layers. This increased remarkably with improved diagnosis by multidisciplinary team, use of clean work over fluid and mechanical isolation of the squeeze point with packer. Recently during 1999-2000, various gels were tested for compatibility with reservoir rock and fluid and accordingly the compatible gels were used in combination with cement cap for Gas shutoff jobs in 6 wells. Test results of 4 wells have shown that two of the four wells have been successful. With improved placement technique the jobs are expected to be more successful.
Monohull Vessel for Subsea Well Intervention
Authors: Vorkinn P. B. , Friedberg R. , Hoemsnes L. 
Published: December 2007

Abstract
This paper describes a conceptual design of a subsea well intervention unit. The Intervention Service Unit (ISU) is a fit for purpose monohull vessel.
Focus on operational efficiencies and cost reduction has been important in the design phase, while prioritizing solutions, which minimize health, safety and environmental (HSE) exposure.
Scope of work for the ISU is wireline operations, coiled tubing and pumping services, subsea equipment installation and maintenance, well clean-up, testing and coiled tubing drilling.
High operability in harsh environment, such as the northern North Sea, is a major design parameter.
The general section of the paper explains the basic engineering execution and the overall specification structure of the concept, from the generic Functional Specification through the more detailed Building Specification.
Some of the challenges which were identified and the unique solutions developed, are described. This includes work over open water and at elevated levels, splash zone issues, handling of heavy loads on a moving structure, amongst others.
Formation Treating with Coiled-Tubing-Conveyed Straddle Tools
Authors: Giroux Richard , Hoffman Corey , Wilson Paul 
Published: December 2007

Abstract
In many wells it is advantageous, both economically and operationally to perform stimulation techniques using coiled tubing. More often than not this process will require that the zone of interest be isolated for the treatment to be effective. Several basic means of isolation are available depending on whether the application requires intervention through tubing or into a monobore, or "tubingless", completion. These basic tools require some form of pipe manipulation to set and retrieve, which in straight holes presents little difficulty, but in deviated wells becomes problematic. As the deviation from vertical increases and eventually reaches horizontal, tool manipulation becomes increasingly difficult and eventually impossible.
To address this problem in highly deviated wells a new generation of downhole straddle tools has been developed which requires no pipe manipulation to set and retrieve. These tools, called Fluid Velocity Set devices, use fluid pressure build up created when pumping through a nozzle to activate and relaxation of that pressure to deactivate a tool. Two distinct types of tool have been developed: Inflatable straddle packers for through tubing applications, which can be inflated to seal in an I.D. up to 2.5 times larger than the running O.D.Mechanical straddle packers for monobore applications, which have a running O.D. small enough to pass through standard tubing mounted accessories, such as landing nipples and sliding sleeves, and set in the tubing I.D.
This paper will discuss the advantages and disadvantages of commonly used isolation methods and will detail the design, development and testing of these new tools. Using recent field tests the authors will illustrate that this type of tool provides a functional and cost effective method of isolating zones in highly deviated and/or horizontal well sections.
Innovative Solution to Prevent Coiled Tubing Operational Failures Caused by Human Errors
Authors: van Adrichem Willem P. , Adnan Sarmad 
Published: December 2007

Abstract
The impact of an operational failure during a coiled tubing (CT) intervention is typically more severe than that of other failures because of the nature of the activity. Failure of the tubing or any component of the well intervention process in a live well scenario can compromise well control and/or the safety of personnel. Statistics on causes of CT operational failures (OFs) indicate that a majority of these failures can be attributed to human error. Incorrect actions, or the lack of action, are very difficult to predict and therefore a major challenge to control. Running CT in and out of the well involves a high degree of human interaction and human fatigue, and short periods of inattention during this process are not uncommon.
During such activities, inattention can lead to actions that damage, kink or part the CT, with potentially disastrous results. Other causes for OFs include unintentional tensile overloads, overpressuring, runaways and other such events. An electric over-ride device, developed for installation in the hydraulic circuitry of a CT unit, allows setting of limits on all pertinent operating parameters of the injector head. Setting equipment limits for weight, velocity and pressure gives the operator an extra set of eyes, greatly increasing operational safety and efficiency of the treatment.
This paper discusses OFs caused by human error and presents case histories that contributed to the conclusion of which parameters require control. The over-ride device used in the control process is discussed in technical detail, and case histories demonstrate the impact of its use on overall safety and service quality in the CT industry.
Case Study of Estimated vs. Actual Coiled Tubing Forces
Authors: Lizcano E. , Higuera J. , Crow W. 
Published: December 2007

Abstract
Job planning considerations, including coiled tubing forces, can be critical factors for the type of equipment and the associated risk of a wellbore entry. This paper presents estimated and actual values and explains the useful range of friction factors associated with the wellbore geometry. Emphasis is placed on the situation where equipment and tubular capabilities are close to safe operating limits. Operational alternatives are discussed which can help manage the risk and aid contingency planning.
Outline Operations plan to perform acid stimulation using 1.75" OD QT900 coiled tubingEstimated forces were 34,000 lbs at TD of 15,400’ MD (with flowing well and brine in CT)Survey shows average DLS of 1.25 down to 15,000’ with a maximum of 4.3 DLS at 8600’Show excel plot of well trajectory in 3D for azimuth changeWellbore entry with periodic weight checks up to maximum of 58 Mlbs pull at 12000’Attempted loading the well with fluid to increase buoyancy without success.Used friction reducer mixed at 5% by volume to decrease friction, but obtained only 10% reduction (or 7 Mlbs).Well entry planned with new friction factors to match the actual weight checks and using QT110 CT with friction reducer.Not many wells with this type of azimuth change in the BP data set.Should consider this limit to well servicing during drilling operationsLow IPR did not justify another cleanout attempt, but perforated upper intervals instead.
Need data from follow up operation (if any) to show the effect of change in planning procedure.
Possible mathematical factor applied to azimuth change to increase friction factor for future CT force estimates.