bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Applications for Wellbore Progressing Cavity Pumps
Authors: Mills R.A.R. , Gaymard R. 
Published: December 2007

Abstract
The application of Progressing Cavity Pumps ("PCP's") for artificial lift is still new compared to other technologies. The technology is advancing rapidly and that, combined with new techniques which are learned empirically, continually expands the range of applications. Continuous review is necessary to stay abreast of the technology. This paper discusses the state of the art and the directions in which it is going.
Increasing the range of application of PCP's is mainly dependant upon the advancement of elastomer technology. A review of the elastomers now being used or tested, their application and how they are made, is presented.
Rotor life is often the determining factor in PCP life. PCP suppliers are doing novel work in plating and hardening of rotors. Some of this work is described.
As the displacements of PCP's increased and they were used at greater depths, the increasing torsion on the drive strings created a serious safety hazard and the drivehead designs became increasingly inadequate for the larger loads. The status of the work to create a set of standards which can be incorporated into safety legislation, and upon which petroleum engineers can rely to select driveheads for safety and reliability, is described. This includes the design criteria which must be considered in the selection of a drivehead.
The status of the work on ISO norms is also reviewed.
Two novel applications for wellbore PCP's are revealed. The conclusions and recommendations summarize the applications and limitations of PCP's for artificial lift.
Introduction
The PCP is a type of spiral gear pump. The principle of the PCP was disclosed by Mr. Rene Moineau. Oil well PCP's are very simple pumps consisting of only 2 parts; the stator which is usually attached to the end of the tubing, and the rotor which is usually attached to the end of a sucker rod string. In this case, the pump is powered by rotation of the sucker rod string. The principal and the geometry of the PCP which make it the best sludge pump and particularly suitable for the pumping of deep wells, have been described in previous papers.
PCP's first found wide application in Canada, for pumping sand-laden heavy oil. The capital cost and operating cost advantages led to the application of PCP's for artificial lift of medium crude, usually with high volumes of water. This required the development of high volume pumps with elastomers which resist aromatic solvents and H2S. PCP's with high head rating were first developed for pumping high viscosity crude oils, but can also be used to lift low viscosity crude from deeper wells. This has lead to the requirement for pumps which resist high temperatures and the high aromatic solvent contents of some light oils. Steam flood applications also introduce the requirement for high temperature resistance.
PCP's have also been used extensively in the USA for the dewatering of methane coal-bed wells, although they have been phased out in most fields in favour of small pump jacks as the water production declined.
Thin Gel Treatment of an Oil Producer at the Gullfaks Field: Results and Evaluation
Authors: Rolfsvag T.A. , Jakobsen S.R. , Lund T.A.T. , Stromsvik G. 
Published: December 2007

Abstract
The use of Na-silicate gel in producers is a method to reduce watercut and improve oil recovery by diverting the flow of water in the reservoir. This has been tested twice at the Gullfaks field in the North Sea and the results are encouraging.
This paper focuses on the second treatment at Gullfaks October 1994, where more than 4000 m3 of gelant solution were injected into a partly watered out zone in a producer. The treatment resulted in a reduced watercut and increased oil recovery from the Lower Rannoch formation. Additional oil production of 130,000 Sm3 by the year 2000 is predicted. The added net present value due to this gel treatment is estimated to more than 50 million NOK's at 10% discount rate.
Input parameters used to describe the gelation process and the effect of Na-silicate gel in a numerical simulator are given.
Microscopic Observations of Oil Displacement in Water-Wet and Oil-Wet Systems
Authors: Donaldson Erle C. , Thomas Rex D. 
Published: December 2007

Abstract
Laboratory studies of the behavior of crude oil and brine in a waterflood were conducted using micromodels packed with graded sand. Flow mechanisms and residual oil patterns were observed and photographed through a microscope. The wettability of the micromodels, which possessed many of the over-all characteristics of reservoir rocks, ranged from strongly water wet to strongly oil wet.
Observations of waterflooding showed that each fluid moves through individual networks of interconnected pores during the period of oil production. The size of trapped oil pockets production. The size of trapped oil pockets behind the water front depends upon the wettability of the system. The rapid development and growth of water fingers ahead of the front resulted in early water breakthrough in the oil-wet systems. The length of these fingers ahead of the front depended upon the wettability of the system. When additives were used to stimulate residual oil production, three distinctly different types of residual-oil flow mechanisms were observed. These can be described as slug flow, globular flow, and extraction.
Sandstone cores were used to determine quantitatively the effect of wettability on oil displacement and relative permeability. The results of these tests of different wettability systems are in good agreement with visual observations of the micromodels. Strongly water-wet systems produce more oil and have better displacement efficiency than oil-wet systems.

Introduction
The USBM has long recognized the need for more knowledge about the mechanics of fluid flow within the pore spaces of reservoir rocks. This knowledge is necessary for development of new and improved methods of oil recovery. Waterflooding is the main process used for the secondary recovery of oil, and wettability has long been recognized as an important factor in this process. The importance of the relative wetting tendencies of oils to production and techniques for measuring wettability have been discussed by many researchers.
Micromodels have been used to observe and study fluid-flow behavior during simulated waterfloods. Chatenever described flow mechanisms and residual oil patterns in a model using-glass and/or Lucite beads with water and filtered crude oil. (Reference to specific brands is made for identification only and does not imply endorsement by USBM.) Mattax and Kyte used a network of interconnecting capillary grooves etched into a flat glass plate to observe more closely the behavior of water and refined oil at the interface. Morris and Wieland used a glass bead model with water and a highly refined kerosene to study the effect of varying the wettability. In this research, micromodels packed with clean graded sand were used with centrifuged crude oil and simulated brine.
New Approach to Extended Well Testing in the North Sea Increases Cost Efficiency
Authors: Burris Wesley Jay 
Published: December 2007

Abstract
Economic conditions in the oilfield have identified many areas in which traditional operating procedures are no longer cost effective and must be replaced by alternative methods with more stringent economic parameters. In the UK, this trend has been embodied in the "Cost Reduction in the New Era (CRINE) Initiative."
This paper will present a method used by one service company in the UK to develop an extended well test (EWT) process plant within the CRINE disciplines. By making modifications to existing equipment, the expenditure for new equipment was reduced. This innovative strategy allowed the service company to develop a processing plant that would meet all operational requirements within the operator's cost objectives.
The case history will provide:
The cost to build the extended well test (EWT) processing plant using modified existing equipment compared to the cost of the EWT if new equipment had been used. Methods for modifying existing resources to meet other early production system (EPS) applications. Methods for modifying similar industry pressure vessels for EWT or EPS applications. Information on how long-term labor-cost reductions can be generated.
Gas Well Optimization: Using Velocity As The Key Component in Choosing Tubing Size
Authors: Cox Sidney G. 
Published: December 2007

Abstract
Because depletion drive and partial water drive gas-condensate reservoirs diminish in pressure with production, flow conditions are continuously changing. Choosing the optimum tubing size for this type of wells can be made easier by use of a nodal analysis program to aid in identifying production velocities. More specifically, the seemingly intuitive conclusion that smaller tubulars will always be required during the latter stages of production in order to unload liquids may not be correct. In particular, when flowing bottom hole pressures on high productivity wells reach the low values of 500 to 1,000 psi, fluid loading considerations can become insignificant when compared to frictional losses caused by the unusually high velocities found at these low pressures. Nodal analysis is indispensable for identifying these situations. By performing a few basic sensitivity runs on bottom hole pressure and liquid yields, a confident recommendation can generally be made on whether one tubing size will serve the life of the well or if a size change is advised later in the well life.
Is There a Hope for Adsorbed Natural Gas (ANG) Vehicles ?
Authors: Cárdenas A. R. , Lagoven S. A. , Pilehvari A. A. , Heenan W. A. 
Published: December 2007

Abstract
In light of tighter restrictions on vehicle emissions and the existence of abundant resources, natural gas represents a highly attractive transportation fuel. Worldwide, there are currently more than 976,000 natural gas-vehicles, most of which are located in Europe and South America.1 At present, Compressed Natural Gas (CNG) is the technology most widely used, which stores gaseous fuel at very high pressures (about 3,000 psig). However, short driving ranges and questions of safety and cost have limited the penetration of Natural Gas Vehicles (NGV) into the transportation market in the U. S. This is in spite of the relatively lower price of natural gas compared with other fuels on an energy basis. A new technology called Adsorbed Natural Gas (ANG) is being developed, which contains the gaseous fuel in a dense form at a moderate pressure (500 psig). The lower pressure utilized by ANG allows the usage of conformable tanks which overcomes the short driving range of CNG. Nonetheless, the hope for ANG vehicles depends on further development in the areas of heat management and gas conditioning, in order to preserve the gas tank capacity.
Advanced Type Curve Analysis for Low Permeability Gas Reservoirs
Authors: Cox D. O. , Kuuskraa V. A. , Hansen J. T. 
Published: December 2007

Abstract
This paper presents new performance type curves for hydraulically fractured wells. The new curves are similar to the Fetkovitch curves for decline curve analysis, but have been developed specifically for fractured wells with linear flow instead of conventional wells with radial flow. Hydraulically fractured wells exhibit different flow regimes than conventional wells, including a skin-dominated period during clean-up, bilinear flow, linear flow, pseudo-radial flow, and boundary- or interference-affected flow. The type curves were constructed in Laplace domain for constant reservoir properties, and were then inverted numerically. The effect of varying reservoir properties was incorporated using an average compressibility determined from material balance.
The type curve methodology provides a new tool for the reservoir engineer to perform rapid analysis of reservoir properties (kh), fracture effectiveness (Xf), and well drainage area (A) for fractured wells. The impact of skin on performance is considered, along with the effect of reservoir geometry (alternative length-to-width ratios) that enable these type curves to be used on lenticular formations. The type curves also include variable compressibility and viscosity that are missing in prior work. More than 1000 tight gas wells in the Green River and Piceance basins have been analyzed using the type curves, and relevant examples from these two basins are presented.
Global Optimization Techniques in Gas Allocation for Continuous Flow Gas Lift Systems
Authors: Buitrago S. , Rodríguez E. , Espin D. 
Published: December 2007

Abstract
Continuous flow gas lift is one of the most common artificial lift methods in use. It works by injecting a continuous volume of high pressure gas into the tubing or tubing/casing annulus to lighten the column of oil and thus facilitate extraction. Excessive gas input is costly because of high gas prices and compressing costs. Inefficient gas allocation in a field with limited gas availability also reduces production and profitability.
Historically, a sensible allocation was achieved using a technique called the equal slope allocation method. This method uses graphical procedures to optimally allocate gas to a group of wells in order to optimize total oil production. However, there is a disadvantage in this method, as it can not be applied to wells where there is not an instantaneous response to gas injection.
The purpose of this paper is to present a methodology for automatically determining the optimum gas injection rate for a group of wells in order to maximize the total oil production rate for a given total amount of gas.
The search algorithm proposed is a combination of stochastic domain exploration and a heuristic calculation of a descent direction, in order to avoid stopping the algorithm at a local optimum.
Well-Surface Connection Controls for Gas Reservoir Simulator
Authors: De Moegen H. , Nabil R. , Lehuen P. , Sonier F. 
Published: December 2007

Abstract
History matching on a 'well by well' basis of the measured and simulated results is obtained from standard general-purpose reservoir simulator.
Predictions of performance and deliverability of a gas storage reservoir, design of a gas storage reservoir and simulation of peak requirements are very man-time intensive and cannot be accurate enough without correct handling of the well-surface connection.
This paper describes the recent development of the well-control options which generalises and facilitates the use of Gaz De France's in-house 'multi-gas'/water underground gas-storage reservoir simulator.
Description of the conditions, constraints, and actions at each level (well, platform and terminal station) and solutions are rigorous. All rate and pressure conditions at the wells, target rate and a common single pressure at the platforms and terminal are solved with no approximations, because, for gas storage reservoir simulations, the results and solutions of typical scenarios are extremely sensitive to a very small change in pressure; therefore, the solution must be as accurate as possible.
A comprehensive range of features, constraints and actions is available on pressures, rates, rate ratios, gas concentrations, volumes, saturations, pipes, compressors and gas treatment.
Full-field study and example applications show the utility of this important option.

Introduction
Compared with improvement of simulators, with features such as, for example, fully implicit scheme, naturally fractured reservoir description, compositional modelling, flexible gridding, history matching, etc. for helping the user during the matching stage of a reservoir study, it seems that up to 1995, very little progress has been made about the prediction or the pre-development planning stage of the reservoir study.
The utility of integrating surface facilities to the reservoir model for 'well management' has been set out in some early publications in the 1980's and also in some commercial simulators showing features that include well-centre field-control and target facilities. A paper described an integrated surface facilities/reservoir simulator for the gas storage industry. In 1995, three papers were presented at the 13th SPE symposium on Reservoir Simulation:
P. 461
Horizontal Well Applications in the Guymon-Hugoton Field: A Case Study
Authors: Granger M. J. , Strickling R. W. , El-Rabaa A. M. , Ortez Y. P. 
Published: December 2007

Abstract
Horizontal well activity has increased in the United States and has proven successful in numerous applications. This paper presents the steps undertaken to optimize the application of fractured horizontal technology in a shallow, low pressure gas reservoir. An application of limited entry technology to create a longitudinal propped fracture through a predrilled liner was developed. Available data for fracture direction, acoustic logs, and mechanical property measurements were used in designing the fracture treatment. Tagging the pad, sand, and resin coated sand with isotopes was used to verify the fracture extended along the entire horizontal lateral.
Laboratory NMR Relaxation Measurements for the Acquisition of Calibration Data for NMR Logging Tools
Authors: Ohen Henry A. , Ajufo Austin O. , Enwere Paulinus M. 
Published: December 2007

Abstract
This paper presents results of laboratory studies of nuclear magnetic resonance (NMR) relaxometry for NMR log calibration aimed at enhancing petrophysical measurements in oil wells. Relationships between NMR longitudinal relaxation parameters and the Hydraulic Units (HU) concept for predicting petrophysical properties from wireline logs have been established previously. However, modern NMR logging tools measure the transverse relaxation parameters. Hence in this paper, we show that measurements of the transverse component of the NMR signal can provide the same information as the longitudinal.
Laboratory NMR transverse relaxation characteristics of water in rock samples were measured with CoreSpec-1000. The NMR data were used to validate models for predicting permeability and producible fluid in clastic rocks. The predictive model for permeability includes the rock surface area to grain volume (Sgv) the tortuosity of the flow paths (), the shape factor (Fs), the transverse relaxation time (T2), relaxivity (), and porosity (). The models were used to develop the required NMR log calibration. The transverse relaxation parameters were used with core analysis data of permeability, porosity, and mercury injection capillary pressures to sort the rock samples into hydraulic (flow) units. Protocol for the use of laboratory NMR core spectrometry and core analysis data for NMR log calibration is presented.
Relationships between T1 and T2, and between flow zone indicators (FZI) and relaxivity () were established. It was observed that T2 cut-off (T2c) is related to T1 cut-off (T1c) in the same way that T2 is related to T1. Relaxation time cutoffs are used for determining producible fluid (free fluid porosity or free fluid index, FFI). The results show that reliable prediction of permeability and producible fluid from NMR logging tools requires calibration of the tools with laboratory NMR measurements on representative rock samples. We demonstrate the use of T2c for determining FFI from T2 distributions. The methodology for identification and characterization of HU within geological facies based on NMR T2 was validated.

Introduction
The (HU) concept has successfully been integrated with laboratory core NMR measurements for evaluating petrophysical properties from wireline logs (Ohen et al.). The HU and NMR techniques were linked through the FZI and NMR relaxation parameters, because both the FZI and the relaxation parameters are related to the rock surface phenomenon which controls the microscopic attributes of the rock. Ohen et al. measured the longitudinal (spin-lattice) relaxation time (T1) on a number of reservoir rock samples at a Larmor frequency of 1 MHz with the CoreSpec-1000.
P. 329
A Technical and Economical Evaluation of Steam Foam Injection Based on a Critical Analysis of Field Applications
Authors: Delamaide E. , Kalaydjian F. 
Published: December 2007

Abstract
The use of foam to improve sweep efficiency during gas or steam injection has been studied since the end of the 50s. Foam reduces the mobility of gas or steam and this effect is amplified when the permeability increases, thereby correcting the effect of heterogeneity. However, although the consequences of the process are now generally recognized, it is still impossible to quantify them in terms of increase in oil production or reduction of quantities of gas/steam injected. The analysis of the field tests that have been performed in the past 20 years can help in the quantification and forecast of foam performance.
This paper presents conclusions resulting from a comprehensive analysis of steam-foam field tests. They show that, at the present time, steam-foam injection is most efficient in layered reservoirs. Injection of slugs of surfactant with steam in this type of reservoirs can yield an average 3.9bbl of incremental oil per kilogram of surfactant injected. The process is economically attractive even in these times of low oil prices, with a cost of $2 to $3 per barrel of incremental oil.
Continuous injection of surfactant with steam, more adapted to in-depth mobility control in non-stratified, heterogeneous reservoirs. It is a much less efficient method, with an average efficiency of 0.3 bbl of incremental oil per kilogram of surfactant injected, and is not economical.
Finally, guidelines for the design of steam-foam injection tests are provided, and injection pressure during steam-foam is related to steam quality and concentration of the surfactant.
Stimulation by Defoaming Increases Thermal Oil Production
Authors: Juprasert Max S. , Davis Bruce W. 
Published: December 2007

Abstract
Foamed oil emulsions can exhibit significant increases in apparent viscosity due to the entrainment of gas bubbles in the oil. Crude asphaltic components act as natural foaming and emulsifying agents. Their influence causes a large portion of the dissolved gas, which would otherwise be liberated as free gas, to remain entrapped in the water-in-oil emulsion as small bubbles. Such in-situ generation of foamy oil emulsions in the vicinity of the wellbore can have a profound effect on well productivity.
This type of formation damage has been found to be fairly common in low gravity oil reservoirs where steamflooding or steam stimulation is used to enhance oil recovery. A novel well stimulation technique, applying a blend of defoaming and demulsifying surface active agents with a bullhead squeezing technique, has proven to be successful in the Cymric and McKittrick fields, California. The cost of incremental oil gained is less than $1.00 per barrel.