bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Two-Phase IPR Correlations for Horizontal Wells
Authors: Kamkom R. , Zhu D. 
Published: December 2007

Abstract
To predict well performance for horizontal wells, several analytical models have been developed to generate inflow performance relationships (IPR) for single-phase wells. Similar to vertical wells, analytical solutions of IPR in two-phase flow horizontal wells are unavailable because of the complexity of relative permeability and the variable phase distribution in the reservoir. Correlations, lead by Vogel's equation, have been used for two-phase IPR calculations for vertical wells, and the methods have been adopted for horizontal well applications.
This paper reviews several two-phase correlations for horizontal wells (Bendakhlia and Aziz's equation, Cheng's equation, and Retnanto and Economides’ equation). Instead of using the original formula of Vogel's equation, these models include the effects of reservoir recovery factor or fluid bubble-point pressure on IPR behaviors. We also presented a modified Vogel's correlation for two-phase horizontal IPR following Kabir's work. The modified correlation uses Babu and Odeh's single-phase horizontal well model to calculate the absolute open flow potential, qo, max, and then uses the original Vogel's correlation to generate the relationship between flow rate and pressure. The reservoir anisotropy is considered in Babu and Odeh's model for horizontal well flow. The results of the modified Vogel's equation are compared with the reviewed two-phase correlations, and also checked against the results from a reservoir simulator (Eclipse™). It is found that the modified Vogel's equation results in close predictions of two-phase inflow performance for horizontal wells at normal recovery factors compared with the reservoir simulation results. At low recovery factor, it deviates from the simulation results more than some other correlations reviewed. For low bubble-point pressure fluids, flow conditions in the reservoir are more likely to be single-phase rather than two-phase, and gradually tranforms from single-phase to two-phase flow as the reservoir pressure declines. The modified Vogel's inflow equation does not capture this transient period; neither do the other correlations reviewed in this paper.
The modified Vogel correlation for two-phase flow horizontal wells is simple compared with the other models, and works as well as the other models at the normal flow condition. It can be used to estimate horizontal well performance conveniently.
New Considerations for Modeling Plunger Performance
Authors: Garg D. , Lea J. F. , Cox J. , Oetama T. 
Published: December 2007

Abstract
The rising portion of plunger cycle makes use of some type of designed sealing mechanisms on the plunger. These sealing techniques reduce the amount of gas that bypasses (leakage) the surfacing plungers. When falling, many plungers have mechanisms designed to allow increased leakage or slippage enabling the plungers to fall faster.
Modeling techniques, for leakage about a rising plunger, shown in this paper are shown as analogous to orifice type flow restriction. For fast falling plungers the model is developed is similar to objects experiencing drag in a field of gas velocity. Data collected for this type of modeling is presented from suspension tests and confirmed with dynamic test data. Model ratification is done with some dynamic test data. Special two-piece and conventional plungers are hereby modeled from suspension and dynamic testing.
The results should help the operators to select specific plunger hardware for specific conditions and should assist in modeling plunger cycles.
Managing Process Risk of Field Facilities
Authors: Johnstone J. E. , Jensen J. R. , Stegall R. P. 
Published: December 2007

Abstract
Managing the risk of oil and gas field facilities is necessary to assure that operations do not pose a significant hazard to the public or those individuals who operate and maintain them. This paper reviews the efforts of BP to implement a company-wide program to manage the risk of oil and gas field facilities.
The growth of BP over the past few years has brought together properties from many different companies in varied geographic locations. BP was challenged with having to safely operate thousands of wells, pipelines, compressors and field separation facilities built to different standards, throughout several generations, in many different states. A new approach was needed to provide assurance that these facilities were constructed and operated safely.
The process to assure that facilities were constructed and operated in a safe manner was broken down into series of steps. The first step was to define risk factors. These factors included rates, pressures, proximity to public areas and the composition of produced fluids. After defining the risk factors, it was necessary to establish design and operational requirements to mitigate the risk. These included use of safety devices, facility design, hazard mitigation measures and management systems. Next, each facility had to be "graded" against the risk factors to determine the relative risk of each facility. Equipment, operational or management system changes had to be next determined for each facility, if necessary. Finally, modifications to the equipment or operating systems to mitigate the risk were implemented.
This paper discusses each of these steps in detail, which BP employed to mitigate operational risk at its oil and gas field facilities.
Applying a Reservoir Simulation Model to Drill a Horizontal Well in a Post-Steamflood Reservoir, Wilmington Field, California
Authors: Hara P. S. , Mondragon J. J. , Sun H. H. , Yang Z. , Ershaghi I. 
Published: December 2007

Abstract
This paper is a case study on the use of a simulation based reservoir evaluation method that led to the drilling of a new well in a seemingly semi depleted steam flooded part of a Fault Block in the Wilmington Field, California. Observations made on this well led to the initiation of a very progressive re-development plan for the area. Information generated from the study should be of significant help for re-development of countless similar field operations that have undergone prior thermal flooding.
The City of Long Beach (City) and Tidelands Oil Production Company (Tidelands) drilled and completed a post-steamflood horizontal producing well, UP-957, into the D1 sands of the Fault Block II-A Tar Zone (Tar II-A) in the Wilmington Field, California in March 2004. The well was directionally drilled along the top and most updip structural position of the D1 Sands. The well penetrated the oil-depleted steam chest interval in the main steamflood area and was completed in a relatively immature steamflood area into the highest remaining oil saturated sands in the Tar II-A. The completion interval was selected based on a 3-D deterministic reservoir simulation model with thermal capabilities developed as part of a United States Department of Energy Class III Reservoir project. Prior to this operation, the developed model was successfully used to convert the Tar II-A steamflood operation to a post-steamflood operation. The model employed a flank cold-water injection strategy between two faults to increase and maintain reservoir pressures to prevent steam chest collapse and surface subsidence1.
Well UP-957 produced at a peak initial oil rate of 249 BOPD and 723 barrels of gross fluid at a wellhead temperature of 197°F and a pumping fluid level of 2122 ft over the mid-perforation depth of 2403 ft VSS (vertical subsea depth), confirming the potential shown by the model. Since the initial response, the oil rate has declined to 130 BOPD and 1991 BGFPD after nine months of production.
Novel Technique for Improved CT Access and Stimulation in an Extended-Reach Well
Authors: Nasr-El-Din H. A. , Arnaout I. H. , Chesson J. B. , Cawiezel K. 
Published: December 2007

Abstract
Drilling technology advances have extended the reach of well depths and complicated trajectories which have in turn created challenges for rig-less well intervention around the world. Extended reach horizontal wells up to 25,000 ft deep require that coiled tubing designs be carefully analyzed to determine when weight stacking and lock-up will prevent coiled tubing from reaching the desired total depth. If the well requires stimulation, then the benefit of coiled tubing is its enhanced placement capability to uniformly inject a treatment across a desired interval. An effective treatment diverting method can further improve these results, especially when coiled tubing is not able to access the entire pay interval. When coiled tubing locks-up before reaching the total depth for one of these treatments, a decision must be made to bullhead the treatment into the lower unreachable section, hoping for uniform placement, or to employ technology which can extend the reach. Larger diameter coiled tubing, coil tractors, liquid friction reducer, mechanical vibrational friction reduction, and buoyancy effects are techniques which can extend the reach of coiled tubing.
Sensitivity analysis was run for the aforementioned techniques and a new vibrational tool combined with a liquid friction reducer on 2-inch coiled tubing was chosen to successfully acid stimulate a horizontal open hole well. This configuration allowed the coiled tubing to reach 25 percent further than the initial lock-up point and the combination of this technique with a new viscoelastic surfactant diverting system, successfully treated the damaged well for a gain of 6,000 BOPD.
This paper will review the stimulation design process and three innovative technologies which have been combined with coiled tubing to successfully treat extended reach wells in Saudi Arabia.
Interpretation of Temperature and Pressure Profiles Measured in Multilateral Wells Equipped with Intelligent Completions
Authors: Yoshioka K. , Zhu D. , Hill A. D. , Lake L. W. 
Published: December 2007

Abstract
This paper presents methods to interpret measurements in complex wells (horizontal, multilateral and multi-branching wells) to determine the inflow profiles of oil, gas and water. These methods are needed to take full advantage of intelligent well, a technology that is rapidly evolving to continuously and permanently monitor downhole temperature, pressure, and perhaps volumetric flow. To realize the value of intelligent wells, the efficient and accurate interpretation of the raw data being acquired is needed.
The interpretation of flow profiles of horizontal or multilateral wells from temperature and pressure profiles requires consideration of subtle effects that are often neglected. In this paper, we illustrate how some of these effects can be predicted, and how they can be used to evaluate complex well performance. In particular, we will highlight the following characteristics of flow in horizontal wells, each of which can provide information about the inflow profile of the well.
Firstly we discuss about Joule-Thomson effects (the heating of oil and the cooling of gas) on the temperature profiles, seeing if they are noticeable changes or not. The discrete production cases are then considered to infer how the pressure or temperature profiles retain marks where the production starts and ends. Also, we examine well trajectories effects. Small inclinations (+2° and -2°) in nominally horizontal laterals affect both pressure and temperature profiles. The differences in potential energy in up-inclined and down-inclined segments may prove to be diagnostic of relative flow rates of the phases. As a last example, water entry effects on the each profiles are shown. When the production becomes oil and water two-phase flow, the fluid properties change and affect the both profiles. In certain cases, the location of the water entry may be noticeable.
Primary and Secondary Oil Recovery From Different Wettability Rocks by Countercurrent Diffusion and Spontaneous Imbibition
Authors: Hatiboglu C. U. , Babadagli T. 
Published: December 2007

Abstract
This study investigates optimum matrix oil recovery strategies in naturally fractured reservoirs (NFR) for different wettabilities and rock types. We compare the recovery efficiencies of two cases: (a) the primary counter-current spontaneous imbibition followed by the diffusion of a miscible phase (secondary recovery) and (b) primary diffusion of miscible fluid without pre-flush of matrix by the spontaneous imbibition. For these recovery strategies, the effects of the matrix shape factor, matrix wettability, and type of miscible displacing phase on the rate of recovery and development of residual oil saturation were clarified experimentally.
Cylindrical Berea sandstone and Indiana limestone samples with different shape factors were obtained by cutting the plugs 1, 2.5, and 5 cm in diameter and 2.5, 5, and 10 cm in length. All sides were coated with epoxy except one end. Static imbibition experiments were conducted on vertically situated samples where the matrix-fracture interaction took place upward direction. Mineral oil and crude oil were used as oleic phases. Brine was selected as aqueous phases for the primary spontaneous imbibition recovery. For primary and secondary miscible displacement experiments n-heptane was used as solvent. Wettability of water-wet Berea sandstone samples was altered to weakly water-wet to observe its effects on the dynamics of spontaneous counter-current imbibition and diffusion.
Parametric analyses were performed for the appraisal of secondary and tertiary recovery potential of naturally fractured reservoirs by immiscible and miscible fluid injections. The optimal recovery strategies (recovery rate, recovery time and ultimate recovery) for different rock properties were identified and classified. In water-wet cases, starting the recovery with capillary imbibition followed by diffusion was found the optimal way, i.e. both effective and efficient. For limestone or aged sandstone samples, starting the recovery by diffusion yielded a faster recovery rate and higher ultimate recovery.
Valhall Field Coiled Tubing Post-Fracture Proppant Cleanout Process Optimization
Authors: Zhou W. , Amaravadi S. , Roedsjoe M. 
Published: December 2007

Abstract
The standard well-completion method in the Valhall field has evolved since 1996 to include multiple proppant fractures along the horizontal laterals. Coiled tubing (CT) has been used since then to perform over 200 post-fracture proppant cleanout operations. Field practices were developed from these jobs but the process in different stages of proppant cleanout operations had not been systematically optimized to realize best performance until the launch of a new process to optimize CT proppant cleanouts.
In May 2004, a study of proppant cleanout process optimization was completed by analyzing historical cleanout performance and incorporation of a new, integrated wellbore-cleanout system to improve operational efficiency through optimized processes, improve safety and reliability by implementing standardized procedures, and reduce stuck-pipe potential through improved design. This study analyzed the whole process of proppant cleanout, captured best practices through validation of field experience, introduced innovations to routine operations, and engineered a new, more efficient cleanout procedure for field operations.
The field implementation of this new process optimization on the first three wells, a total of 22 zones, indicated a significant performance improvement. The optimized process saved a total of 6 days’ working time and encountered zero incidents that might have led to stuck pipe. The new cleanout procedure was followed by different operational crews on the job and has been adopted as a best practice for future wells.
This paper details the engineering and implementation of CT post-fracture proppant cleanout process optimization in the Valhall field and demonstrates a step-change improvement in Valhall CT cleanout performance during the past 9 years.
Successful Coiled Tubing Water Shutoff Solution for a Horizontal Sand Screen Completion Using Novel Fluids
Authors: Tudball I. , Mcginn P. , Watson D. 
Published: December 2007

Abstract
This paper describes the results obtained, the techniques used, and the challenges involved in providing a water shutoff solution to a subsea gas production well with a sand screen completion on the Rose field in the UK Southern North Sea.
The project began with a detailed reservoir analysis to determine if intervention was practical in this subhydrostatic well. This led to the planning and sourcing of suitable coiled tubing (CT) and pumping equipment, as well as an associated zonal isolation chemical solution.
The design of the intervention was tailored to operate within the environment of a jackup installation located over a subsea well. This included CT and fluid pumping operations. The basis of the technique was to shut off the water-producing interval in the horizontal completion and isolate the unsupported annulus between the water bearing and gas producing intervals. The greatest challenge was to isolate the horizontal annulus between the gas and water producing zones. This required setting of mechanical barriers and the placement of suitable zonal isolation material that would set quickly without slumping and leaving the top of the annulus unsealed. This paper details the lessons learned throughout the intervention.
In the case of the Rose well, it now produces dry gas. This was the first time globally that this technique had been applied to a subsea horizontal well.
Reservoir Monitoring with Pulsed Neutron Capture Logs
Authors: Morris C. , Aswad T. , Morris F. , Quinlan T. 
Published: December 2007

Abstract
Efficient reservoir management requires that the latest pulsed neutron capture (PNC) tool technology be comparable with the older measurement results to provide continuity, precision, and accuracy in the monitoring program. A new sigma processing technique was developed for the dual-burst pulse neutron capture measurements that maintains the resolution and repeatability of the new-generation tools but provides results needed for reconciliation with the older generation tools used for more than 20 years in reservoir monitoring. The sigma processing technique is described relative to the old and new generation tools, which utilize radically different approaches. General considerations of repeatability and accuracy are discussed which apply to PNC logs and their use in both stand-alone and time-lapse techniques.
More than 35 cases have been evaluated with the new processing technique. Examples are presented to show reservoir monitoring results obtained in a variety of formation lithologies, formation fluids, and borehole environments to illustrate the robustness of the technique. These cases include detailed analytic studies between the PNC tools. The results indicate that the new sigma processing can provide direct time-lapse reservoir monitoring continuity and yield accurate reservoir saturation analysis.
The Application of a Reduced Polymer Borate System
Authors: McDonald C. E. 
Published: December 2007

Abstract
The amount of polymer damage created by a fracturing system has been a problem for many years. Polymer damage results in the reduction of fracture conductivity and effective propped fracture length. One method to reduce polymer damage is to reduce gel loadings. Historically systems that were developed to reduce polymer loadings have encountered numerous problems. The limiting factor for reducing the amount of polymer in a fracturing system is the point where the viscosity of the fluid is not adequate to transport proppant. In areas of low permeability gas wells, poor proppant transport results in less than desired production due to decreased fracture length in the reservoir.
Many of these low-polymer fracturing systems are not operationally feasible due to the lack of a suitable water source for the system to yield its peak viscosity. In addition to the operational issues of locating a suitable water source, another constraint on some of these systems is the requirement to use a liquid KCl substitute in place of granular KCl. These issues have limited the use of the low-polymer systems in many areas. The shear sensitivity associated with the use of organometallic crosslinkers is a problem encountered by many low-polymer systems. High tubular velocities will shear degrade the fluid reducing it's proppant transport capability compared to that of a borate crosslinked system.
This paper will discuss a modification to a well-established borate crosslinked fluid and system that eliminates these problems. Case histories will be given for the applications and results of this reduced polymer system that yields comparable viscosities to higher polymer loading systems.
Waterflooding in Chalk: Relationship between Oil Recovery, New Wettability Index, Brine Composition and Cationic Wettability Modifier
Authors: Zhang P. , Austad T. 
Published: December 2007

Abstract
Naturally fractured carbonate reservoirs are usually neutral to preferential oil-wet, which prevents water from being an efficient IOR-fluid. Spontaneous imbibition of water into the matrix blocks is believed to be the key mechanism for improved oil recovery by waterflooding. In previous study, it was documented that the wetting condition of carbonates was mainly dictated by the acid number, AN, of the crude oil. In the present study, series of long-term spontaneous imbibition tests were conducted at 70°C on chalk cores representing different wetting conditions. The oil recovery is discussed in terms of a new wetting index and the property/composition of the imbibing fluids. Synthetic seawater was used as the base imbibing fluid, and model Ekofisk formation water was used as initial water present in the cores. The cores were aged in crude oils with different AN and at a variety of temperatures ranging from 40-120°C. Major observations are: (1) Good relationship between the new wetting index and oil recovery was established. (2) The water-wet fraction of the chalk surface must be above 0.6 for spontaneous imbibition to occur.(3) Sulfate in the imbibing fluid appeared to have a wettability modifying effect, especially at low water-wet conditions. (4) Cationic surfactant of the type [R-N(CH3)3]+ dissolved in the imbibing fluid improved the oil recovery significantly, especially close to neutral wetting conditions. The effects of sulfate on the oil recovery is discussed in terms of potential determining ions towards chalk, as well as its potential as wettability modifying agent.
An Interwell Water Flood Study: Flow Pattern and Reservoir Heterogeneity Evaluation of a Northern Field Formation in Mexico, Part I: Upper Section of the Field
Authors: Reyes-Lopez C. , Marhx-Rojano M. A. , Asadi M. , Casas D. R. 
Published: December 2007

Abstract
A successful reservoir flood depends on prior knowledge of the flow stream within a reservoir and a proper injection/production pattern. A northern field formation in Mexico, which currently includes 44 injectors and more than 150 producers, has been under water flood since early 1965. Due to the loss of injection fluid and low sweep efficiencies a chemical interwell tracer program was designed and implemented to fully investigate the flow stream within the current injection/production pattern and to evaluate reservoir heterogeneity. However, based on the results of seismic and well test analysis and due to the large number of active injection and production wells, the entire field was divided into four sections for this interwell tracer study. This paper presents the interwell study results for the upper section of the north field, which includes seven injectors (A to G) and 36 producers (1 to 36). A detailed interwell study over a 10 month period indicated the existence of massive high-permeability channels as well the existence of a major fault initiating from this section and extending downward into the lower section of the field. Also, the results indicate the existence of several transverse faults along the main fault. Detailed graphical results to identify the flow stream, a comprehensive interpretation of the heterogeneity of the formation, and tracer travel time are also presented.