bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Capillary Viscometer for the Study of EOR Polymers
Authors: Liauh W. W. , Liu T. W. 
Published: December 2007

Abstract
This paper describes the design and principles of operation of a new capillary viscometer that was developed to measure viscosities of dilute EOR polymer solutions under conditions involving both high temperature and low shear rate. Development of this viscometer was undertaken primarily because there are no commercial viscometers available to make measurements under these conditions. The viscometer was designed so that it could also be used at low temperatures and at high shear rates. In addition, it has the capability to qualitatively determine the viscoelastic character that polymer solutions often exhibit in porous media.
Some results obtained with the capillary viscometer are also presented. This viscometer has been used to make viscosity measurements at shear rates ranging from 0.01 to 10,000 sec−1 and at temperatures from 20 to 99°C. Results obtained to date indicate that the viscosities of different polymers respond quite differently to changes in temperature. For example, compared to the two most commonly used EOR polymers--xanthan bio-polymer and polyacrylamide--scleroglucan bio-polymer has a more favorable viscosity-temperature relationship. The effectiveness of the scleroglucan polymer, as measured by its viscosity relative to water, increases with temperature, while that of the other two polymers decreases with temperature. In general, the relationship between viscosity and temperature is an important consideration in selecting the most effective polymers for high-temperature applications.
Methods of Enhancing Fluid Communication in Oil Sands
Authors: Tam E. S. , Edmunds N. R. , Redford D. A. 
Published: December 2007

Abstract
Effective steamflooding of oil sands requires fluid communication between injectors and producers. Such a communication path can be developed through a naturally occurring zone of low bitumen saturation. If a water sand with little or no bitumen saturation is encountered, high injectivity can be achieved and a steamflood can be carried out immediately. With zones having mobile water and some bitumen as well, special enhancement processes are required to prevent tar bank ing when steam is injected which is common in steam drive processes where cold bitumen is displaced ahead of a steam front. One way to prevent tar banking is to heat the mobility zones slowly with hot water so that hot bitumen will be displaced when steam drive is initiated. Depending upon the nature of the mobility zones, the efficiency of the enhancement process might be improved by the use of solvents such as naphtha or synthetic crudes.
In this study numerical simulation was used to develop a communication enhancement process which involves the stimulation of production wells with hot water followed by hot water injection into the injection well. A reservoir description was assumed with initial mobility such that a steam drive process could not be started readily. Results of the study indicate that the communication path can be heated gradually using production wellbore stimulation and hot water injection. However, the process is not effective for low mobility zones. In the latter case organic solvents may be used to enhance the process. The study generally outlines the range of permeability thicknesses for which hot water can be used as an enhancement agent. The possibility of using CO2 as a viscosity reduction agent was also considered. Results show that CO2 injection cannot attain mobile conditions for the bitumen unless the reservoir pressure is sufficiently high. On the other hand, CO2 has an adverse effect on water injectivity; CO2 is not recommended as a communication enhancement agent unless sufficient high injection pressure is used.
CO2 Miscible Flooding Evaluation of the South Welch Unit, Welch San Andres Field
Authors: Keeling R. J. 
Published: December 2007

Abstract
The South Welch Unit, in Dawson County, Texas, was selected as a miscible flooding candidate in 1981 based on the recommendation of a feasibility study. The central 300 acres (1,214 Mm2) of the unit were designated as the Phase One area, and infill drilling of this area was begun in 1981. CO2 injection was initiated in February of 1982 with CO2 trucked to the location in liquid form. Simulations were made to predict the recovery from the Phase One area under several production methods. These methods included:
20% IHCPV slug CO2 injected continuously 20% IHCPV slug CO2 injected using a 2:1 4 cycle WAG 25% IHCPV slug CO2 injected using a 2:1 5 cycle WAG Continued waterf looding on 20 acre line drive patterns
All simulations were made with the current CO2 supply limitations taken into consideration. The 25% slug, 2:1 5 cycle WAG case is the optimum mode of operation based on sensitivity studies.
CO2 Flooding a Waterflooded Shallow Pennsylvanian Sand in Oklahoma: A Case History
Authors: Kumar Rajeshwar , Eibeck J. N. 
Published: December 2007

Abstract
ARCO Oil and Gas Company started work on a CO2 Tertiary Pilot in the Garber field located in Garfield Co., Ok. in 1980. Garber is a Pennsylvanian age, multiplay field, discovered in 1916. It has produced in early years under depletion drive and later by waterflooding. The purpose of the pilot was to investigate the tertiary oil potential of the shallow sands which were previously waterflooded to depletion. CO2 was injected into the Crews sand, a shallow Pennsylvanian sand located at an average depth of 1950 ft (594 m). Prior to the start of the pilot program, the depleted Crews sand waterflood was not producing in the pilot area. The main pilot is a 10.4 acres (4.2 ha), normal 5-spot, which is enclosed by backup water injectors and outside producers. Water was initially injected in the project area to raise the reservoir pressure and to establish a base production curve. Then a total of 27,000 tons (24,500 × 103 kgs) of CO2, equalling 35% HCPV in the effective area, was injected as a straight slug. The pilot response has been very encouraging. The project has already produced 70,000 STBO (11.1 × 103m3). Ultimate recovery from this pilot should exceed 14% of the original oil in place within the effective area. The success of this pilot suggests that it is possible to CO2 flood reservoirs at depths shallower than previously thought possible.
Enhanced Recovery Surveillance Using Well-to-Well Tomography
Authors: Kretzschmar J. L. , Witterholt E. J. 
Published: December 2007

Abstract
In the past decade, the tools of the petroleum engineer for predicting reservoir behavior have increased significantly in terms of more complete mathematical models and enormously faster computing hardware. Unfortunately, the tools for in situ monitoring of actual behavior are largely unchanged and most often involve data characteristic of only a limited volume around individual wells.
Techniques are now emerging which can provide a more complete view of fluid distributions in the reservoir over the entire distance between wells. These techniques, sometimes referred to as geotomography, use wave propagation between observation wells as a basis for reservoir mapping in a procedure analogous to that used in the CAT scan now common in diagnostic medicine.
Observations on Tailoring Chemical Slugs and Simulating Reservoir Cores for an Oil-Wet Reservoir
Authors: Lorenz P. B. , Tham M. K. , Brock Sylvia , Bayazeed A. F. , Burtch F. W. 
Published: December 2007

ABSTRACT
Results are presented from three areas of the laboratory studies in connection with the surfactant-polymer pilot field test conducted by the U. S. Department of Energy: 1. Sulfonate produced, both in the field and laboratory tests, was chiefly in the oil phase, indicating a marked departure from the optimal condition of equal distribution. This cannot be attributed to increased salinity, as the salinity of the produced brine was not very different from that of the injected surfactant slug. Suggested causes are dilution and changing water/oil ratio that resulted in fractional repartitioning of the complex alcohol and sulfonate.
2. The use of dilute brine instead of fresh water for the polymer slug avoided large variations in viscosity that would have resulted from seasonal variations in the supply water. In this connection, it was found that the non-Newtonian character of the polymer was different for two solutions at the same viscosity but different polymer/salt composition.
3. Berea cores, when fired, behaved like the oil-wet reservoir cores in respect to oil recovery, relative permeability, and flow-resistance history. A supplementary silicone treatment to give the same wettability is the oilfield cores had no beneficial effect.
Geology and Physical Properties of the Monterey Formation, California
Authors: Isaacs C. M. 
Published: December 2007

ABSTRACT
Original sediments of the Monterey Formation have diverse compositions reflecting both paleobasin setting (fine detritus) and oceanographic productivity (silica/carbonate). Varying stages of diagenesis, which includes silica phase transformations and dolomitization, have produced fractured reservoirs characterized by a complex array of rock types with a wide range of physical properties.
Two-Phase Flow and Calcite Deposition
Authors: Gudmundsson J. S. , Ortiz-R. J. , Granadso-G. E. 
Published: December 2007

ABSTRACT
The literature on two-phase flow in geothermal wells shows that the Orkiszewski1 method has found wide application in state-of-the-art wellbore simulators. Such a simulator was developed and then used for the problem of wellbore deposition of calcite in the Miravalles geothermal field in Costa Rica. The output of wells suffering calcite deposition decreases slowly at early time but rapidly at late time. The simulator was also used to estimate the deliver ability curve for a large diameter well in the Svartsengi geothemal field in Iceland. The view is presented that more accurate wellbore simulators will make new reservoir engineering studies possible in geothermal fields.
Use of a Mineral Fines Stabilizer in Well Completions
Authors: Borchardt J. K. , Roll D. L. , Rayne L. M. 
Published: December 2007

Abstract
Formation damage in the vicinity of the wellbore is a major cause of low productivity1–6 and the difficulties attendant to restoration of the damage leave a significant number of wells that do not respond to remedial treatment.1 Operators have recognized the importance of damage control during drilling, workover and other operations and have used filtration processes to reduce the damage caused by fluids invading the formation.
Until recently, however, little could be done to control permeability damage caused by the movement of fine particles native to the formation of interest.
Prevention of the migration of fine particles (defined) as those having a diameter less than 44 micrometers and which will pass through the openings of a 325 U.S. mesh screen7) is a complex problem. Certain cationic organic polymers (COP's) have been developed to control the swelling of water-expandable clays such smectite in the presence of low salinity fluids.8–14 While damaging in itself, the major detrimental aspect of smectite swelling is the associated release of fine particles.8 This arises because, when present, the particles. This arises because, when present, the smectite clay frequently acts as the cementation medium holding sand grains and fine particles in place.7,8
Field Application of a Chemical Heat and Nitrogen Generating System
Authors: Mitchell T. I. , Donovan S. C. , Collesi J. B. , McSpadden H. W. 
Published: December 2007

ABSTRACT
Heat is often required to stimulate production in wells with recurrent histories of paraffin deposition and plugging. A chemical system which produces heat and nitrogen at a predetermined well depth is proposed as an alternative to the traditional hot oil and steam generation treatments. The system is described briefly and case histories are given for 3 wells in California and 5 wells in Wyoming.
The field results indicate that heat produced by the nitrogen generating system effectively stimulates production from paraffin plugged wells. The heat and nitrogen generating system further shows increased production cycle lengths over those which result from hot oil or paraffin solvent treatments. Beneficial effects of including a paraffin inhibitor in the treatment design are discussed, along with other potential applications for the heat produced by this system.
Numerical Simulation Of A Reservoir Complex With A Tilting Gascap D5/D6 Sands - Utorogu Field, Nigeria
Authors: Becker-Hoff A.H.F. , McAlpine A. , O'Neill N. 
Published: December 2007

Abstract
This paper presents complete analysis of a tilting gascap reservoir with the reservoir engineering supported by production geology and petrophysics. As a whole the study illustrates that a combination petrophysics. As a whole the study illustrates that a combination of conventional and modern tools, can provide a good insight into the reservoir drive mechanisms. Numerical simulation capabilities (Ref. 1) are discussed in some detail.
Effect of Pressure-Dependent Permeability on Well-Test Analyses and Long-Term Production of Methane From Coal Seams
Authors: Schwerer F. C. , Pavone A. M. 
Published: December 2007

ABSTRACT
Laboratory measurements have shown that the permeability of coal samples varies significantly for ranges of pressure encountered during the testing of coalbed methane wells.
A laboratory pressure-permeability relation has been used with a numerical, two-phase coalbed methane simulator to examine the effect of pressure-dependent permeability on well-tests and on production of coalbed methane.
Evaluation of the Influence of In-Situ Reservoir Conditions on the Geometry of Hydraulic Fractures Using a 3-D Simulator: Part 1—Technical Approach
Authors: Abou-Sayed A. S. , Sinha K. P. , Clifton R. J. 
Published: December 2007

ABSTRACT
A three dimensional simulator based on a coupled hydromechanical analysis is described in the paper. The mathematical formulation is based on analyses of three dimensional rock deformation and two dimensional fluid flow through the fracture. Both the rock deformation and fluid flow problems are solved using variational principles for fracture opening and the fracturing fluid pressure, respectively. The fracture criterion is based on a stress intensity factor approach.
The fracturing fluid is allowed to leak off into a formation at a rate determined by the excess pressure. Linear elastic fracture mechanics concepts are utilized to characterize the critical conditions for fracture propagation as the fluid is injected.
The fracture is assumed to open in a vertical plane and to be perpendicular to the minimum horizontal in-situ compressive stress. The rock mass is modeled as an isotropic homogeneous medium, but variations in permeability and in-situ stress are accounted for. The fracture is created by injection of an incompressible, non-Newtonian fluid with power-law characteristics.
The actual numerical procedure including the details of modeling some important phenomenon such as in-situ stress contrast, fluid loss, etc. has been described.
This paper forms the technical background for a companion paper, part II, in which several case analyses using the 3-D simulator have been reported along with parametric evaluation of the influence of reservoir conditions.
Fluid-Level Determinations Through Internal Flush Tubing Without Depth, Temperature, or Pressure Limitations
Authors: Weeks S. G. , Podio A. L. , McCoy J. N. 
Published: December 2007

ABSTRACT
Potential hazards of wireline exposures to hostile CO2 and H2S environments often discourage running bottom hole pressure (BHP) surveys. While surface pressure build-ups may be utilized for dry-gas wells, detailed analyses may be of limited value where there is also liquid production. However, concurrent fluid level determinations can be used to enhance the value of surface build-ups. Other practical applications of fluid level determinations include a means of monitoring liquid loading or depths of fluid displacement, such as encountered during some stimulation or corrosion inhibition treatments. Detailed testing, of a recently developed high-pressure acoustical well sounder, verifies that fluid levels can now be determined even under the most adverse well conditions.
A Field Study of ESP Performance in a Deep, Hot, and Sour Environment
Authors: Mohrbacher J. D. 
Published: December 2007

ABSTRACT
This paper will outline procedures used to improve electric submersible pump (ESP) run lives in the Beaver Creek Madison (BCM) formation, Fremont County, Wyoming. ESP run lives increased from an average of 66 days in October, 1982, to 241 days by June, 1983. One of the seven ESPs included in this evaluation had run for 332 days by June 1, 1983, indicating run lives on the order of one year are now possible in the BCM. Discussions of installations procedures, operations and failure analysis are included. This paper also presents operating data for ESP equipment tested in the BCM, including two brands of pumps, seals, and motors; four types of downhole power cable; and a variable speed drive. Recommendations for continued improvements are also presented.
Polymer Mini-Injectivity Test: Shannon Reservoir, Naval Petroleum Reserve No. 3, Natrona County, WY
Authors: Doll T. E 
Published: December 2007

ABSTRACT
The Shannon Reservoir, in the Naval Petroleum Reserve Number 3, has the greatest original-oil-in place, and the lowest projected primary recovery of the productive formations in the field. Gravity drainage controls primary production as no active water drive exists and bottom-hole pressure is low.
The Shannon Reservoir is a stratified, heterogeneous, shaly siltstone. Previous attempts at water-flooding, off the Reserve, failed due to direct communication between injector and producer. Polymer improved waterflooding was chosen for the Shannon Reservoir after extensive laboratory core analysis screening. A field test on the proposed pilot site using various concentrations of brine water and the log-inject-log technique for analysis, indicated that sufficient mobile oil was present. An off-pilot mini-injectivity field test evaluation of both a dry and a liquid polymer product system was initiated late in the Fall of 1981.
The results of the off-pilot mini-injectivity test indicated: that Shannon injection well characteristics can be changed by polymer injection; that polymer solution concentration, crosslinking and complexing can be varied for specific desired injection rates and pressures; and that resistance to flow initiated by polymer injection can be maintained with subsequent water injection.
Based on the technical evaluation of this off-pilot mini-injectivity test data, a polymer improved waterflood pilot was constructed. The pilot operation continues at this date with further comments outside the scope of this paper.
Economics and Potential for Mobility Control Methods for CO2 Floods in the Rocky Mountain Region
Authors: Pande P. K. , Heller J. P. 
Published: December 2007

ABSTRACT
A levelized cost procedure is used to determine the profitability of carbon dioxide flooding in the Rocky Mountain Region for non-waterflooded fields, and of the use of thickening agents for mobility control. The effects on production of changing the mobility of the injected CO2 are estimated by use of a correlation developed by Claridge [1] from his analysis of the literature on developed five-spot patterns. The procedure shows that mobility control can be applied profitably to carbon dioxide floods. Greater profits result from operating at lower mobility ratios. The effect of varying critical operation and financial parameters on the profitability of carbon dioxide floods is investigated. The profitability of the project is highly dependent on the cost of carbon dioxide. The oil price, oil price escalation rate, carbon dioxide cost escalation rate, and discount rate for discounting future cost and revenue streams affect the profitability of the project by an order of magnitude less than the cost of carbon dioxide. However, for conventional carbon dioxide floods, carbon dioxide recycling is important and the recycling affects profits more than the parameters just mentioned previously. The cost, concentration, and escalation rates of mobility control agents are also important factors which affect the profitability of mobility controlled carbon dioxide floods. The fixed charge rate for capital and the operation and maintenance cost escalation rate affect the profitability of the flood but these parameters play a far less significant role than any of the other factors described above.
Performance and Economics of Minnelusa Polymer Floods
Authors: Mack J. C. , Duvall M. L. 
Published: December 2007

ABSTRACT
The secondary recovery processes of waterflooding and polymer flooding commonly used in the Minnelusa formation are compared. Flood efficiency is improved using polymer technology. Less water is injected and less water produced to recover a barrel of oil. Flood life is shortened. Results of the Simpson Ranch polymer flood show that investment in polymer technology is profitable.
Subsea Oil Loading System for Tankers
Authors: Sander H. H. , Sterzenbach M. , Wilke K. 
Published: December 2007

ABSTRACT
The offshore oil loading systems known up to the present have many disadvantages with respect to safety and costs. Feasibility studies have therefore been carried out to examine the concept of a subsea oil loading system. This work was followed up by design of the individual components. The investigations are being carried out by DEMINEX, TNSW and AEG. This has resulted in new solutions which enable economical and reliable operations with a high utilization factor even in marginal fields and in water depths down to 200 meters. The fact that the fixed components of the loading system are located on the seabed means that application of the system is also feasible in ice hazard areas.
Newest TFL Retrievable Safety Valves for Subsea Completions
Authors: Yonker J. H. 
Published: December 2007

ABSTRACT
Two new retrievable ball type safety valves are now available in the TFL (pumpdown) configuration. These valves offer greater depths in a more simplified configuration to operators planning subsea completions. They were developed at the request of major producers for use in the North Sea and Southeast Asia.
Design of these new valves began -in 1977 and early 1978 by engineers from Otis' Research and Development Department. One valve is a balance line valve with a fail-close leak protection feature. The other valve is a single line deep set valve which allows installation at greater depths than previously achieved. They have been successfully tested in test wells and test loops at the manufacturer and in two land test wells by the operators. The safety system packages for these valves are currently installed in six subsea wells – five in the North Sea and the other in the South China Sea.
The material presented in this paper shows how the capabilities of subsea production are expanded by the development of a truly fail safe balance line retrievable ball valve and a deep set single line ball valve which can be placed at or near the packer, below paraffin levels, or below the kickoff point.