bluuebunny/crossref_metadata_2025_split huggingface dataset:
Christina Lake Thermal Project
Authors: Suggett Jack , Gittins Simon , Youn Sung 
Published: December 2007

Abstract
This paper provides a description of PanCanadian’s Christina Lake Thermal Project. PanCanadian is implementing a commercial steam assisted gravity drainage (SAGD) project to recover 7.5 to 9.0 API bitumen from the Athabasca oil sands in the McMurray Formation. The project is located in Northeast Alberta, approximately 130 km north of Lac La Biche and 170 km south of Fort McMurray, in township 76 range 6 W4M.
The project will be built in three phases for total bitumen production of 70,000 barrels of bitumen per day. Phase 1 will produce 10,000 bpd, with Phases 2 and 3 producing 30,000 bpd each. This paper will outline PanCanadian’s reasons for taking a phased approach to the Christina Lake development.
Dual well SAGD will be implemented with 500 to 750 m long horizontal well pairs. Phase 1 is expected to begin steaming operations in the fourth quarter of 2001. The timing of subsequent phases will depend on Phase 1 results, market conditions and project economics. In March, 2000 PanCanadian received Alberta Energy and Utility Board approval for the project.
Thermal-Deformation-Resistant Slotted-Liner Design for Horizontal Wells
Authors: Slack M. W. , Roggensack W. D. , Wilson G. , Lemieux R. O. 
Published: December 2007

Abstract
Liners for wells produced using the SAGD process (steam assisted gravity drainage) must balance sand control requirements and inflow characteristics against the structural demands of thermally induced loads. These challenging design issues require a switch from conventional load-based casing design principals to a deformation-controlled design basis. This paper first develops this design basis, describing the problem in terms of the controlling variables, then applies the results to the liner design for a specific reservoir in a reliability based context. The developed design implements innovative and recently commercially available deformation control devices to manage competing thermal and geo-mechanical loads in the intermediate casing and horizontal liner. For the candidate well, a purpose-specific slotting configuration was also defined to control inflow distribution and reduce risk of undesirable slot deformations under thermal loads. (SPE Paper 65517 describes the inflow design basis.) The resulting liner design maintains structural integrity and provides slot geometry protection to ensure effective sand control supporting the extended production life obtained through managed slot distribution.
Optimization Methodology for Cyclic Steam Injection with Horizontal Wells
Authors: Escobar E. , Valkó P. , Lee W. J. , Rodríguez M. G. 
Published: December 2007

Abstract
Horizontal wells are becoming a very important component in the thermal recovery of heavy oil reservoirs. The success of a cyclic steam injection project depends strongly on the selection of key parameters, such as cycle length and amount of steam injected. The numerical simulation of horizontal wells, especially under non-isothermal conditions, is computationally demanding. When optimization is combined with numerical simulation, the computing time requirement may be prohibitive and it is not guaranteed that the optimal conditions will be found.
In this research, a new methodology has been developed for optimizing the cyclic steam injection process for vertical and horizontal wells. The procedure integrates oil production characterization using numerical simulation, net present value maximization through a Quasi-Newton method, and model validation/tuning. The three-stage procedure provides the optimum number and/or duration of cycles, the optimal amounts of steam to be injected in each cycle and the optimal value of the overall economic indicator.
The optimization algorithm was successfully validated with published results obtained from the discrete maximum principle. The methodology was then applied to determine the optimal conditions of cyclic steam injection for a horizontal well located in Bachaquero field, Venezuela.
The Effect of Chain Length of Oil and Alcohol As Well as Surfactant to Alcohol Ratio on the Solubilization, Phase Behavior and Interfacial Tension of Oil/Brine/Surfactant/Alcohol Systems
Authors: Hsieh W.C. , Shah D.O. 
Published: December 2007

The Effect of Chain Length of Oil and Alcohol As Well as Surfactant to Alcohol Ratio on the Solubilization, Phase Behavior and Interfacial Tension of Oil/Brine/Surfactant/Alcohol Phase Behavior and Interfacial Tension of Oil/Brine/Surfactant/Alcohol Systems
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Economical microemulsion flooding process can be achieved by optimizing the surfactant formulation for an oil reservoir. This optimization involves the tailoring of a surfactant formulation to fit the conditions for a reservoir, namely, the temperature, the salinity and composition of formation water, and the nature of the crude oil. The general method of optimization of surfactant formulations is to investigate the phase behavior and interfacial tension of surfactant systems containing brine, oil, surfactant and cosurfactant.
Solubilization of oil and brine by microemulsion phase containing petroleum sulfonate TRS 10–410 and alcohol was determined at room temperature. Interfacial tension between phases was correlated with solubilization phases was correlated with solubilization behavior of surfactant formulations. The effect of the chain length of hydrocarbon oil on the solubilization and interfacial tension behavior of surfactant formulations was investigated at a surfactant concentration of 5 wt.% and isobutanol concentration of 3 wt.%. Effect of chain length and isomeric structure of alcohols on the solubilization and interfacial tension behavior of dodecane vs. surfactant solution containing 5 wt.% TRS 10–410 and 3 wt.% alcohol was investigated and correlated with the solubility of alcohol in brine. Effect of alcohol and surfactant concentrations on the formation and volume of the middle phase was determined. Surfactant to alcohol ratio was changed in the formulation in order to determine the molecular ratio of surfactant to alcohol in the middle phase. The surfactant to alcohol ratio in the middle phase micro-emulsion was determined using high resolution NMR spectroscopy. Interfacial tension was measured as a function of surfactant concentration to find the interfacial tension concentration minima. The minimum interfacial tensions at low and high surfactant concentrations were correlated by changing salinity and hydrocarbon oil chain length in the surfactant formulation.

Introduction
Microemulsion flooding process has been widely tested in laboratory and has been applied in field tests in recent years for tertiary oil recovery. In this process, a microemulsion containing petroleum sulfonate, alcohol, oil and brine was used as an injection fluid. The interfacial tension between the microemulsion and reservoir oil or brine is as low as 10 dynes/cm or less. Under adequate conditions, the microemulsion slug is miscible with both oil and brine.
Enhanced-Oil-Recovery Injection Waters
Authors: Collins A. Gene 
Published: December 2007

Publication Rights Reserved, U.S. Government Publication Rights Reserved, U.S. Government This paper was prepared for the 1977 SPE-AIME International Symposium on Oilfield and Geothermal Chemistry, held in La Jolla, California, June 27–28, 1977. Permission to copy is restricted to an abstract of not more than 300 words, Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made. Discussion of this paper provided agreement to give proper credit is made. Discussion of this paper is invited.

Abstract
A survey was made of the types of waters, chemicals, and water-treatment methods used in enhanced-oil-recovery operations. The study indicated that numerous types of waters, chemicals, and water-treatment methods are used. Chemical and biochemical reactions can occur when different types of waters are mixed, or when enhanced-oil-recovery chemicals are added. Stringent quality control is needed in all operational phases related to injection waters in order to produce optimum amounts of oil and to prevent irreparable damage to equipment, wells, and oil reservoirs. Standard methods are needed to assure adequate quality control.

Introduction
In this report, enhanced oil recovery is defined as the additional production of oil resulting from the introduction of artificial energy into the reservoir. Primary oil recovery is defined as the oil and gas produced by natural reservoir energy or forces. Therefore, by this definition enhanced recovery includes waterflooding, gas injection, and other operations involving fluid or gas injection whether for secondary or tertiary oil recovery. Tertiary recovery is any enhanced-recovery operation applied after secondary recovery. The ERDA research program on enhanced oil recovery does not include waterflooding.
Enhanced recovery is applied to an oil-containing subsurface reservoir for the purpose of dislodging oil from the reservoir rock pores and moving it to a production well. Many subsurface petroleum reservoirs contain sufficient energy because of internal pressures to push oil and gas to the surface when first penetrated by a drill bit. However, as the penetrated by a drill bit. However, as the internal pressures become low because of the removal or production of oil, gas, and water at the wellhead, the residual oil in the reservoir cannot be recovered without the application of external or artificial force.
Secondary recovery is any enhanced-recovery operation first applied to a reservoir. Often it follows primary recovery, but it can be conducted simultaneously with primary recovery. The most common secondary-recovery process is waterflooding.
Experience in Scale Control With East Mesa Geothermal Brine
Authors: Lindemuth T.E. , Houle E.H. , Suemoto S.H. , Van Der Mast V.C. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The East Mesa Geothermal Test Site, near Holtville, California, established by the Bureau of Reclamation, has been involved with studies of resource development and geothermal desalination since 1972. At present, there are five geothermal wells on the East Mesa Anomaly, operated by the government, as well as five others, developed by private interests.
The major program at the site has been investigation of the feasibility of producing pure water from geothermal brines, using producing pure water from geothermal brines, using desalination techniques. Pilot plants installed and operated included two distillation units and a high temperature electro-dialysis unit.
Throughout the last 4 years of investigation, a variety of scaling problems have been encountered. Plugging and fouling of downhole well piping, surface piping, and process units primarily with calcium process units primarily with calcium carbonate, barium sulfate, and silica have been noted.
This paper discusses the conditions under which these observations have been made, including brine chemistry, brine temperature, well flow, and other process conditions. Success has been noted in the use of several scale inhibitor additives, especially in the control of calcium carbonate and barium sulfate scale.
The scale inhibition techniques described in this paper should have applicability in operation of geothermal systems for both power and water production, as well as in the reinjection of waste brine.

Introduction
Since 1972, the U. S. Bureau of Reclamation has been operating a geothermal test facility on the East Mesa, near Holtville, California. The purpose of activities there has been to determine the feasibility of providing a source of augmentation flow for providing a source of augmentation flow for the Lower Colorado River by the desalination of geothermal brines. A unique aspect of this program is the fact that the geothermal brine provides both the source of water and heat to operate the process.
Using Well Windows in Full Field Reservoir Simulation
Authors: Mlacnik M. J. , Heinemann Z. E. 
Published: December 2007

Abstract
The windowing technique, introduced by Deimbacher and Heinemann (Ref. 3), allows a time-dependent replacement of grids for a defined area during a simulation run. A window can represent any kind of well with a gridded wellbore and an appropriate grid pattern around the well. Such an approach makes the generally used Peaceman well model superfluous. As the gridded wellbore and the grid blocks around it are small (some cu-ft) the computational stability requires small timesteps and a greater number of Newton-Raphson iterations. It is obvious that this is not feasible if the solution for the full-scale model and the well windows must be performed simultaneously. Therefore in a first step the fully implicit solution for the full-scale model will be calculated but the inner blocks of the windows are solved for the pressure only, without updating the saturations and mole fractions. This solution provides the boundary influx for the windows. In a second step the windows are calculated for the same overall time step with up to 1000 small local steps.
This paper presents the general and practical applicability of this method. Windows, constructed by the PEBI (k-PEBI) method, are introduced automatically for all of the wells (vertical, horizontal and slanted).
For testing purposes a real case field model was used. It will be shown that the quality of the results obtained for the model calculated with integrated radial grids around the wells and small overall timesteps are equal to those obtained for the same model using the windowing and local timestepping technique.
Further it will be shown that solving the window model with large timestep lengths for the first and small lengths for the second solution step results in equal or smaller CPU times and less NR iterations in comparison to the conventional model.
Emergency Shutdown Systems-Evolution And Status
Authors: Oubre Harold J. , Thurman R. , Vallee J.C. 
Published: December 2007

Abstract
Beginning in the early 1930's the development of downhole and surface safety equipment has followed a logical evolution, through the close cooperation between the operating companies and manufacturers. The separate developments of downhole and surface safety devices were joined with the introduction of the surface controlled sub surface safety valves in the late 1950's. For the first time, truly integrated systems could then be designed for offshore installations instead of the previously available separate safety devices. Safety systems are now in use all over the world that provide safe, reliable emergency shutdown protection against almost any predictable situation.
New Centralizers Improve Horizontal Well Cementing by 100% Over Conventional Centralizers in the Niger Delta Basin
Authors: Peckins Osazuwa , Akhideno Mathias , Faugeras Herve 
Published: December 2007

Abstract
Statistics of cementing highly deviated wells in the Niger Delta (50 deg or more) show that only about 33% are successful and do not require an elaborate squeeze cementing operation. Two out of every six wells drilled in the past had good primary cement bond logs less than an average of 15mv.
The remedial squeeze operations are expensive requiring such operations as perforation of casing which often times reduces the intergrity of this pressure vessels, putting the existing bond at risk and finally the drill out testing of the squeezed casinf intervals. This entire remedial operation is non-productive rig time resulting in increased well cost.
Analysis has traced this poor primary casing cementation history to a number of deficiences (1) Improperly designed cement recipes (2) Poor hole geometry (3) Bad cementing or placement techniques (4) poor casing string centralisation resulting in channelling.
The effect of each of this factor is amplified due to the fact that the Niger delta is characterised by sand /shale sequence which contributes to hole washouts or even caving resulting in hole sizes that are much larger than the bit size.
In the Niger delta, poor casing centralization contributes over 50% of the poor primary cement job. Even good cement recipes and good cementing practices are jeopardised by flow pattern resulting from poor casing centralization.
Operator experience had indicated that the use of conventional spring / rigid type centralizers for casing centralisation in the Niger Delta had not been successful in correcting this deficiency in highly deviated wells.
A new centralizing package has been introduced and successfully used in the cementing of horizontal and multilateral wells.
To authenticate the result from the use of this new package, a study was implemented in the Imo River field of the Niger Delta. The results obtained so far from the cementation of three horizontal wells and the two multilateral wells in the Niger Delta totaling seven horizontal wells, indicates that there is a 100% improvement in primary cementing and zonal isolation. CBL/VDL was logged on all wells, giving excellent results in the profile of 5millivolt with no need for expensive remedial squeeze cementing. (Fig 2).
Actual well candidate selection criteria, technical and economic performance evaluations on the application of this new centralizer package are included in this paper.
Prevention of Corrosion in a Harsh Environment Using Zinc Primer
Authors: Muntasser Z. M. , Al-Darbi M. M. , Paez J. E. , Vaziri H. H. , Islam M. R. 
Published: December 2007

ABSTRACT
Harsh environmental conditions prevail in most petroleum pipelines as well as downhole tubulars. Under these conditions, corrosion can have adevastating effect on both petroleum production and transportation. The petroleum industry has been using inorganic zinc coating as a primer coating that can withstand prolonged services. It is well known that zinc reacts with steel to form a very strong bond that is not easily broken when subjected to HARSH CONDITIONS. However, several areas of weakness persist. There is no existing method to select the most effective primer among many that are available commercially. The current methods do not optimize the thickness of the primer and the mechanisms of corrosion prevention in the presence of abrasive materials are not well understood. This paper addresses these shortcomings of the past and proposes a comprehensive technique for corrosion prevention in harsh environmental conditions.
In a series of experiments, corrosion (both onset and growth) is observed in various pH conditions using various thicknesses of zinc primers. In order to simulate solid/solid interaction (e.g. pipeline in an environment where sands and dusts prevail), sand blasting is performed for a predetermined period. In this, the time of sand blasting was considered to be crucial since the time in the laboratory must be scaled down to model field conditions. For different cases, the nature of corrosion and the extent of growth were observed both in the presence and absence of top coatings. The extent of corrosion under sand abrasion was also observed. A procedure is recommended for determining optimum thickness of zinc primers under various environmental conditions (e.g. pH, sand erosion). Top coatings were found to be necessary for several of the conditions. Fundamental chemistry as well as fractal modeling is used to define the kinetics of corrosion growth. The role of zinc primer in developing a barrier is incorporated. The study results compare favorably with the experimental results
Rotaflex Efficiency and Balancing
Authors: McCoy J. N. , Podio A. L. , Rowlan Lynn 
Published: December 2007

Abstract
The unique geometry of the RotaFlex pumping unit results in a constant torque arm (or torque factor) on most of the upstroke and downstroke. The geometry promotes high electrical efficiencies. These electrical efficiencies can be measured by comparing the work required to raise the produced liquids from the net liquid level depth to the work input to the system as electrical power. Also favorable for high electrical efficiencies is the minimized electrical generation of the RotaFlex pumping unit, when compared to conventional beam pump units. RotaFlex balancing can be performed using electrical power measurements, and the amount of counterweight that must be added or removed from the counterweight box to balance the unit can be calculated directly by software using the power measurements and RotaFlex data. Therefore, power balancing does not require knowledge of the weight of the counterweight box and the auxiliary weights as is required with conventional mechanical balancing. To describe and explain the proper procedure for determining electrical efficiency and balanced torque, an example of electrically balancing a RotaFlex pumping unit to the optimum efficiency is presented.
Determining Frac Effectiveness from Production: Case History
Authors: Rietman Noel D. 
Published: December 2007

Abstract
Thirty-two tight gas wells completed in the Cleveland Formation in Lipscomb County, Texas were analyzed to determine the effectiveness of using production rates to evaluate completion techniques. Production rate tools tested were rate-versus-time, cumulative-versus-time and rate-versus-cumulative graphs of the first six months, twelve months and twenty-four months of production. The standard used to measure the validity of conclusions from the production curves was the frac length of each well as determined by inverted decline curve analysis. Comparisons between offset wells and also between groups of wells (using frac lengths to group the wells into quartiles) resulted in the wrong conclusion about half of the time. In other words, flipping a coin to determine the best frac treatment would have been just as effective as comparing production rates. The most likely reasons for this failure of production rate evaluation techniques are lack of uniformity of reservoir characteristics and boundaries to the drainage area.
The conclusion is that, at least for the wells studied, some analytical method of determining treatment effectiveness such as Fetkovich curves, inverted decline curve analysis or buildup analysis should be used to evaluate various types and sizes of frac treatments. Production comparisons can be misleading if they are not validated by analytical methods.
Corrosion Inhibition/Foamer Combination Treatment to Enhance Gas Production
Authors: Campbell Samuel , Ramachandran Sunder , Bartrip Keith 
Published: December 2007

Abstract
Liquid holdup may decrease the productivity of gas producing wells. The use of foaming agents is a popular method of reducing fluid levels and increasing well production. However, corrosion rates may still be excessive in these cases requiring a mitigation strategy. The use of chemicals that act as foaming agents and corrosion inhibitors have great utility in gas wells with excessive water holdup. The underlying physical principles and measurable parameters include dynamic interfacial tension, foaming ability, and corrosion inhibition. A mechanistic description to predict the performance of chemical foamers is developed based upon measurable parameters demonstrating that the dominant factor is foam density. In addition, the effectiveness of a chemical program to unload a well and inhibit corrosion is demonstrated.