bluuebunny/crossref_metadata_2025_split huggingface dataset:
Insert Chamber Lift Experiences in Mara-La Paz Field, Venezuela
Authors: Gasbarri S. , Marcano L. , Inciarte J. E. , Faustinelli J. G. 
Published: December 2007

Abstract
Several types of fluids and well depths can be found within Mara-La Paz field. Different artificial lift methods have been used depending on the well characteristics. Gas lift is one of the most widespread methods used in the area, and gas compression facilities are used for artificial lifting many wells. The injection pressure is around 900 psi. Continuous gas lift injection is not always profitable, particularly for very low reservoir pressure. In this case, and depending on the well depth, intermittent gas injection may be used to decreased gas consumption and optimize the field.
Most of the wells on this field are too deep for a conventional intermittent gas lift installation. Chamber and plunger lift are alternative applications to improve the profitability of the wells. The purpose of the chamber is to accumulate more liquid volume per bottom hole flowing pressure increase and then, to produce more fluids per cycle compared to a conventional intermittent gas lift system.
Although chamber lift technology has been used for more than 4 decades, little information can be found in the literature about the intrinsic problems and statistics of success of this type of artificial lift system. This paper describes the performance of the chamber lift installations in Mara-La Paz field and the methodology used for design, diagnostic, and optimization of the systems.
A Unique Solution to Zonal Isolation Utilizing Foam-Cement and Coiled-Tubing Technologies
Authors: O'Rourke T. J. , Crombie D. L. 
Published: December 2007

Abstract
To effectively exploit a by-passed underpressured Devonian (D3) pinnacle reef, a horizontal re-entry was planned. Due to the presence of a gas cap and a nearby solvent bank in the reef it was essential that hydraulic isolation be achieved when cementing the build section liner in order to prevent gas migration during oil production from the new wellbore.
Coiled tubing was utilized to clean the formation face prior to cementing; foam-cement was then used to isolate the near wellbore and coiled tubing was once again used to clean out any excess cement from blocking the borehole prior to drilling ahead and cementing the liner.
Application of Geostatistics and Conventional Methods to Derive Hydraulic Flow Units for Improved Reservoir Description: A Case Study of Endicott Field, Alaska
Authors: Ratchkovski Artem , Ogbe David O. , Lawal Akanni S. 
Published: December 2007

Abstract
In this paper, we combine the geostatistical methods of conditional simulation with conventional methods of deriving flow units to characterize a section of the Endicott Field, North Slope of Alaska. Hydraulic flow units are generated using well logs, core data and core descriptions from 10 wells. Geostatistical techniques of sequential Gaussian simulation and sequential indicator simulation were used to obtain equiprobable realizations of the reservoir properties such as porosity and permeability.
Conventional interpolation techniques of inverse distance by power and kriging were also applied to describe the distribution of porosity and permeability in the developed flow units model. To validate conventional and geostatistical approaches, the fluid flow simulations of waterflooding were performed in the small section of Endicott Field. Results of the waterflood performance showed that geostatistical models give more detailed description of the reservoir heterogeneities compared to conventional methods.
Multiphase-Flow Properties of Fractured Porous Media
Authors: Rangel-German E. , Akin S. , Castanier L. 
Published: December 2007

Abstract
The fluid transfer parameters between matrix and fracture are not well known. Consequently, simulation of fractured reservoirs uses, in general, very crude and unproved hypothesis such as zero capillary pressure in the fracture and/or relative permeability functions that are linear with saturation. In order to improve the understanding of flow in fractured media, an experimental study was conducted and numerical simulation used to interpret experimental results.
A laboratory flow apparatus was built to obtain data on water-air imbibition and oil-water drainage displacements in fractured sandstone systems. During the experiments, porosity and saturation were measured along the core utilizing a Computerized Tomography (CT) scanner. Saturation images were reconstructed in 3-D to observe how matrix-fracture interaction occurred. Differences in fluid saturations and relative permeabilities caused by changes of fracture width have also been analyzed.
In the case of water-air imbibition, fracture systems with narrower fracture apertures showed more stable fronts and slower water breakthrough than the wide fracture systems. However, the final water saturation was higher in wide fracture systems, thus showing that capillary pressure in the narrow fracture has more effect on fluid distribution in the matrix. During oil-water drainage, oil saturations were higher in the blocks near the thin fracture, again showing the effect of fracture capillary pressure. Oil fingering was observed in the wide fracture.
Fine-grid simulations of the experiments using a commercial reservoir simulator were performed. Relative permeability and capillary pressure curves were obtained by history matching the experiments. The results showed that the assumption of fracture relative permeability equal to phase saturation is incorrect. We found that both capillary and viscous forces affect the process. The matrix capillary pressure obtained by matching an experiment showed lower values than reported in the literature.
Optimization of Slimhole Dual-Body Bits by Experiments and Computational Fluid Dynamics
Authors: de Sousa J. T. V. , Prohaska M. , Bencic A. , Millheim K. K. 
Published: December 2007

AbstractThis paper presents a detailed study on the optimization of slim-hole dual-body bits made in-house for use in Coring-While-Drilling (CWD). Investigations consisted of extensive coring and drilling laboratory tests in soft, medium and hard rocks. In addition, an apparatus was designed and built to investigate the effect of the rotary speeds on the pressure distribution underneath the bits. To calibrate the experimental work, Computational Fluid Dynamics (CFD) techniques were used to investigate the flow characteristics of the bits.
Badami Development
Authors: Repp S. A. , Ennis J. O. 
Published: December 2007

Abstract
Badami is the first "greenfield" production facility on the North Slope of Alaska in over 10 years. Smaller than previous developments and remote from existing infrastructure, Badami was sanctioned in February 1997 and began oil production on August 23, 1998. Innovative approaches to project definition and execution were applied in order to achieve project sanction and breakthrough performance as measured by cost and schedule. Lessons from Badami provide a model for the next generation of smaller remote developments in Alaska.
Badami was developed on a fast track with parallel activities in reservoir definition, facilities engineering, and permitting.
A facilities project alliance made up of BP and the primary engineering and construction contractors was formed at the start of the conceptual design phase. The intent of the alliance was to align the interest of BP and the contractors in a risk/reward profit scheme and to reduce development costs through the innovation and challenge to conventional approaches that motivated partners would provide.
Waterflood Pattern Allocations: Quantifying the Injector to Producer Relationship with Streamline Simulation
Authors: Grinestaff G. H. 
Published: December 2007

Abstract
SPE Distinguished lecturer Anil Kumar states that industry wide injection wells are overlooked, neglected, and mismanaged. Historically, injection patterns have been described by neighboring producers. Production is allocated back to injectors using angle open to flow or volume and distance weighting methodology. These static allocation methods poorly represent the physics involved in determining flow paths in the reservoir between wells.
Through the use of streamline simulation, Dynamic Injection Pattern Allocations accurately describe waterflood patterns through time. By quantifying the injector to producer relationship, inefficiencies in the waterflood are readily seen and the benefits of injection well work quantified. Waterflood injector rates can be set to maximize oil production, instead of maximizing water injection.
This paper demonstrates how to use streamline simulation to proactively manage a waterflood. The paper focuses on three areas: 1) how streamline models require a different approach to simulation, 2) using streamlines to find inefficiencies in the waterflood and set injection targets, and 3) the benefits of a history matched model.
Schrader Bluff CO2 EOR Evaluation
Authors: McKean T. A. M. , Thomas A. H. , Chesher J. R. , Weggeland M. C. 
Published: December 2007

Abstract
A CO2 miscible gas enhanced oil recovery (EOR) water-alternating-gas (WAG) development scheme is being evaluated as a method to enhance viscous oil recovery from the Schrader Bluff reservoir at Milne Point.
A CO2 EOR development offers the opportunity to reduce greenhouse gas emissions, while at the same time enhancing oil recovery. Under such a scheme, CO2 would be extracted from the exhaust of gas-fired turbines and compressed for injection along with NGL in a WAG flood. There are no known analogues using this approach to increase recovery in a viscous oil reservoir.
Fully compositional simulation models were constructed to investigate the behavior of the injected CO2/NGL mixture as compared with conventional waterflood recovery schemes. An assessment of simulator capability was made, and uncertainties in reservoir properties and development options were examined with a variety of models. The overall performance of the CO2/NGL solvent was predicted for pattern elements, scaled up to development pad size, then to a multi-pad large-scale development.
The evaluation concludes that CO2 EOR WAG has the potential to significantly increase recovery compared to water-flooding, and that a large volume of CO2 could be permanently sequestered in the reservoir. The economic viability of the project depends on the value attributed to the sequestered CO2 in the form of emission permits which are sold or traded.
Reservoir Engineering Aspects of Horizontal Wells in Stochastic Naturally Fractured Gas Reservoirs
Authors: Hatzignatiou D. G. 
Published: December 2007

Abstract
This work presents the application of a newly developed gas reservoir numerical model for simulating gas flow in naturally fractured reservoirs capable of handling stochastically generated natural fracture network systems. The motivation for this study is based on the inability of traditional dual-porosity reservoir models to represent effectively fracture networks, in the form of either clusters of intersecting fractures or fracture discontinuums. The simulator assumes single-phase, dry-gas flow in a bounded, naturally fractured gas reservoir. The model decouples fluid flow in fracture and matrix domains, thus solving a one-dimensional matrix flow problem to compute the volumetric flow rates from matrix into fractures and/or wellbore(s). Subsequently, the model uses the recharge fluid rates entering the fractures at the middle point of each fracture segment to compute the pressure and flow rate distributions at each node of the system by solving a two-dimensional fluid flow problem in the fracture domain. The system of natural fractures is produced using a stochastic fracture-porosity model which generates fracture network realizations and provides data regarding the natural fractures (location, apertures, density, clustering, etc.). The gas reservoir simulator is validated, for simplified reservoir problems, against a commercially available three-dimensional, three-phase, black-oil simulator and used to conduct a preliminary study of the pressure behavior and recovery of natural gas from a tight gas formation in Paludal Sands of the Rulison Field, Piceance Creek Basin in Colorado. Simulation results of a horizontal well in this naturally fractured gas reservoir indicate that well location within the flow region, degree of clustering, fracture density, fracture aperture distribution, and degree of fracture interconnectedness are very significant factors influencing gas production rates, gas recovery and reservoir drainage effectiveness.
Multiple Hydraulic Fractures in Horizontal Wells
Authors: Wan J. , Aziz K. 
Published: December 2007

Abstract
A well model is required to relate the well rate to the well pressure and the block pressure containing the well for the modeling wells in simulators. The well index is calculated automatically by simulators for conventional wells, but it is generally calculated by the user and supplied in the input while modeling non-conventional wells, when the default procedure available in commercial simulators is not adequate.
In this paper we describe a new analytical solution for horizontal wells with multiple fractures. The fractures can be rotated at any horizontal angle to the well and they need not fully penetrate the formation in the vertical direction. This three-dimension solution for hydraulically fractured wells is obtained by applying Fourier analysis to a two-dimensional solution, therefore this three-dimension solution is easy to obtain when the two-dimensional solution is available. The analytical solution provides the well pressure that can be combined with a numerically computed gridblock pressure to obtain the well index (WI). Results of our rigorous solution are compared with empirical approaches currently in use for calculating the well index and the productivity index. Examples are given when horizontal wells with fractures are modeled using our new approach and conventional methods. These results demonstrate the need for computing the correct WI.
Management of Well Production Using Real-Time Expert Systems Technology
Authors: McLean Dan , Wilcoxson Jim , Clay Roger 
Published: December 2007

Abstract
Management of well production for artificially lifted wells can be improved using expert system technology to combine real time sensor information with production engineering knowledge rules. When abnormal conditions exist on a gas well it is not always apparent that there is a problem until significant production loss and/or the results of other regulatory control system alarms become apparent. By applying expert system technology and elements of artificial intelligence, visualization of well performance in relation to the well design can be presented to operations personnel in real time. The well performance can then be maximized once the operating constraints are known and algorithms to optimize production can logically follow. The expert application describes in this paper demonstrates this ability and can be extended easily to multiple well sites or multiple platforms and fields.
Planning Exploratory Drilling for Coalbed Methane Resource Development in Rural Alaska
Authors: Ogbe David O. , Clough James , Bott Jamie , Hawley Mary A. 
Published: December 2007

Abstract
The state of Alaska contains over 40 trillion cubic feet of conventional natural gas and 5 trillion short tons of coal reserves. Although the actual extent and magnitude of producible gas from Alaska's remote coal basins are unknown, the Alaska Department of Natural Resources postulates that if only 10% of the estimated 1,000-trillion cubic feet of methane gas is recoverable, this coalbed methane resource would triple the State's current proven conventional gas reserves
Exploratory drilling is the key to assessing the potential of the coalbed gas resources from Alaska's vast coal reserves. In this paper, we evaluate the feasibility of drilling exploratory wells for developing coalbed methane resource as alternative energy in rural Alaska. The paper presents detailed analysis of the costs of drilling exploratory wells, including logistics and transportation, geological and hydrologic testing at three sites in rural Alaska.
The results of the study show that the cost of drilling and testing two exploratory test wells is about $1.8 million at each site. The study recommends guidelines for site selection, well planning, and design of drilling programs to support coalbed methane development in rural Alaska.
A Fundamentally New Model of Acid Wormholing in Carbonates
Authors: Gdanski Rick 
Published: December 2007

Abstract
A new theoretical model has been developed to describe the chemical reactions of acid in porous carbonate media. For the past 20 years, the three major unanswered questions regarding wormholing when acid is pumped into carbonate formations have been the following: (1) How many dominant wormholes are created? (2) What is the spatial distribution of those dominant wormholes along the wellbore? (3) What is the leakoff profile from the dominant wormholes under radial flow conditions? This paper presents a model that proposes answers to these three basic questions. Once these questions are answered, the reaction of acid in the matrix and the interaction of wormhole development become straightforward. The new model requires a major paradigm shift in the understanding of matrix carbonate acidizing and the variables that control wormhole growth. Parametric studies that were conducted with the new theory are presented. It was found that wormhole length is predominantly controlled by matrix porosity and volume of acid pumped—not by reactivity. It was found that wormhole diameter is predominantly controlled by reactivity and contact time. The new theory confirms classically held guidelines for matrix acidizing of carbonates, and gives insight on how to improve matrix carbonate acidizing treatments. The new model also accommodates the effects of permeability anisotropy caused by natural fracturing or layering effects
Chelating Agents in Sour Well Acidizing: Methodology or Mythology
Authors: Brezinski Michael M. 
Published: December 2007

Abstract
Metal chelating materials have been used as iron control agents in acidizing treatments for many years. There are several disadvantages associated with use of the various commercially available products. These disadvantages include low solubility and high toxicity. Furthermore, recent evidence casts considerable doubt on the effectiveness of common chelating agents for iron control in sour environments.
A relatively simple procedure will be presented that allows preparation of pure metal (calcium and iron) chelant complexes. These complexes serve as models for the in-depth evaluation of various chelating agents over a broad range of temperatures and fluid compositions and have been characterized with respect to solubility and thermal stability in spent acid fluids. The experimental results show loss of solubility of calcium complexes as well as thermal decomposition of ferrous complexes at relatively low temperatures. Implications of these results will be discussed.
The problems are exacerbated in sour environments where iron sulfide precipitation occurs at a very low pH. New evidence will be presented that shows iron sulfide precipitation will occur below the pH range where chelating agents are effective. The precipitation of iron sulfide has been found to be dependant upon formation basicity and NOT the overall acidity of the bulk fluid as commonly believed. The result implies that simple equilibrium calculations may not reliably predict the chemistry that will occur downholeand must be used with caution.
The conclusion drawn from these results is that the only effective method of preventing precipitation of iron sulfide during sour well acid treatments is to remove H2S from the fluid with sulfide scavenger products. The elimination of large quantities (6–36 kg/m3, or 50–300lbs./Mgal) of chelating agents will have significant cost savings with regards to fluid cost. The evidence provided in this paper shows that these products are not effective and even worse, may precipitate in the formation and cause severe damage
New Fluosilicic Acid System Removes Deep Clay Damage
Authors: Da Motta Eduardo P. , C. M. Dos Santos J. Altamiro 
Published: December 2007

Abstract
Recent models for sandstone acidizing have shown that the secondary reaction of fluosilicic acid (H2SiF6) with clays plays a significant role in the removal of formation damage. The conventional wisdom is that possible precipitation during the secondary reactions can adversely affect treatment success. However, this paper presents laboratory experiments with Berea cores and two Brazilian sandstone cores, as well as field tests, which show that fluosilicic acid can be injected, by itself, into a sandstone reservoir without causing any damage at all. Quite the contrary, mixtures of fluosilicic acid with a proper amount of hydrochloric acid (HCl) or an organic acid such as acetic acid (HAc) have been able to improve the performance of two Brazilian water injection wells by removing clay damage. These two wells, that were injecting 11 and 15 m3/d, are sustaining injection rates at or above the desired quota of 30 m3/d, five months after the treatments. The treatments were monitored with a real-time monitoring program, that showed that the skin factor has dropped from about 30/40 to zero. Besides having a lower cost than conventional HF mixtures, the main advantage of the new acid system is that it reacts mostly with clays and feldspars, but almost does not react with quartz. This way, it can dissolve damage without weakening the rock structure, what makes it suitable for deep damage removal. The low cost of H2SiF6, which is a byproduct of sodium fluoride manufacturing, makes it also a viable option for routine acidizing operations, that would normally require the use of an HF acid system.
Screen Sizing Rules and Running Guidelines to Maximise Horizontal Well Productivity
Authors: Malbrel Christophe , Procyk Alex , Cameron John 
Published: December 2007

Abstract
Flow density across sand control screens in horizontal wells is very low. This is very favorable to the selection of screen-only completions as a cost effective sand control measure. However, phenomena specific to horizontal well completions have prevented them being as successful as they could be: 1) deployment contaminates the screen and reduces well productivity; 2) formation sands can mix in the annulus around the screen, modify the apparent sand sieve analyses, and affect the screen's ability to retain sand.
Therefore, screen sizing must not only include the selection of a screen medium capable to retain formation sands and tolerant to impairment caused by completion fluids, it also requires a careful review of other screen design features such as diameter, OD/ID ratio and the screen/blank ratio. To help select screens, sizing guidelines have been developed based on formation sand characteristics such as average size (D50) and uniformity (D40/D90).
A well productivity model has also been developed to assist in screen selection. Using reservoir characteristics such as permeability, heterogeneity, consolidation, design flowrate and fluid characteristics, it shows that incomplete screen clean-up can seriously affect well performance. While gravel packing reduces productivity losses associated with poor screen clean-up, minimizing screen impairment during deployment and/or cleaning it afterwards can prove to be a less costly alternative. A "Mud Plugging Index" is proposed to monitor screen plugging by a given drill-in fluid and help optimize fluid conditioning on the rig. Using centralizers on the screen during deployment and back-flowing fluid with a washcups assembly will also help enhancing well productivity.