bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparison of Actual Results of EOR Field Projects to Calculated Results of EOR Predictive Models
Authors: Pautz J. F. , Welch R. A. , Nautiyal C. M. 
Published: December 2007

Abstract
The 1984 National Petroleum Council (NPC) enhanced oil recovery (EOR) study used five computerized EOR process predictive models to estimate the potential for EOR. These models were reviewed by industry representatives and determined to be accurate when used with representative reservoir data. These models have continued to be a primary tool to assist the Department of Energy (DOE) and other agencies of the federal government to assess policy alternatives for tax reform, environmental regulations, petroleum research, and others areas. It is believed the estimates made by the models are representative for the United States petroleum resource although they may not be accurate for any one specific project or reservoir. Until recently, there has not been a data source that can statistically verify that belief.
The DOE encouraged EOR projects by starting the Tertiary Incentive Program (TIP) in 1978. Details of proposed projects were submitted, and the projects were certified as qualifying projects. Production and fluid injection data from those projects have been voluntarily submitted to the DOE since 1982. This program has produced historical data on more than 100 EOR projects with sufficient data for comparison with simulations using the predictive models. ՛
In this work, the predictive models were run using the average wellhead crude oil price for each year from 1980 to 1991 to estimate the potential production of the projects. The calculated production from the models was compared with the reported actual production until the project was terminated or no more production was reported. The results showed that steam production estimates were reasonable with a 50% confidence level for individual projects, whereas aggregate oil production for a group of projects compared more favorably. A rough estimate of the accuracy of the total aggregate oil production for a group of projects was ±20% at the 75% confidence level. Availability of data for other processes were insufficient for complete statistical analysis. Results for miscible gas projects showed that the carbon dioxide predictive model makes conservative estimates of tertiary oil production but optimistic predictions when the total oil target is considered. The surfactant option of the chemical flood model and the in-situ combustion model made reasonable oil production predictions. The polymer model made oil production estimates much higher than that reported for polymer augmented waterfloods.
The measured accuracy is for the combination of the models and the data. The results indicated that first upgrading the data and then the models would be desirable. Although this study indicates reasonable results for a group of reservoirs or projects, there was low confidence in predicted oil production for individual projects.
Master Plan To Increase Profitability of Heavy Crudes and Bitumen
Authors: McGee J. H. , Yibirin J. G. , Joubert Geovanny , Gallardo Bahilda 
Published: December 2007

Abstract
One of the largest accumulations of heavy oil and bitumen in the world are associated to Venezuelan reservoirs, where the Orinoco Belt alone has some 1.2 × 1012 Bis. of oil in place.
It is a well known fact that production of heavy oil and bitumen presents additional difficulties, as compared to more conventional hydrocarbons, in aspects such as: reservoir engineering, well completion and artificial lift, as well as surface facilities and associated procesess. These additional difficulties impact in high investments and production cost, which together with low market price result in marginal profitability.
In orden to improve these margins of profitability, a master plan was designed and implemented which consist in analyzing each aspect, considering new technology or new applications of existing technology that could make these hydrocarbons more competitive. Care was taken in that these technologies could interact with each other.
The following discussion is organized with projects with final evaluation first, on going projects next and future projects last. Also, where possible a sequence from reservoir aspects, to well completion and surface facilities is followed.
A Review of IOR/EOR Opportunities for the Brent Field: Depressurisation, the Way Forward
Authors: Braithwaite C. I. M. 
Published: December 2007

Abstract
Under the current waterflood development, it has been predicted that gas production from the Brent Field will fall off plateau in 1998 and, at field abandonment approximately 55% of the 6.9 Tscf GIIP and 54% of the 3600 MMstb STOMP would be recovered.
A review of EOR/IOR techniques was carried out at an early stage to define which of the various processes might be applicable in the Brent Field and would warrant further evaluation. The scouting study considered microbial, thermal, chemical, gravity drainage and miscible processes as well as reservoir depressurisation.
Of all the possibilities, surfactant flooding, immiscible (or near miscible) gas Injection and depressurisation were found to be technically viable. However, based on an estimate of the costs involved it was established that only reservoir depressurisation was economically attractive under the current and projected oil price trend.
With its high solution gas-oll-ratio (ranging from 1500 to 3000 scf/stb), depressurisation of the field, ultimately to 1000 psi, would liberate a significant proportion of the remaining solution gas and raise recovery by 1.5 Tscf. It was also established that, by extending the field's life, oil and condensate recovery would be Increased by 30 MMstb compared to a continuation of the ongoing waterflood.
Before the project could be initiated uncertainties such as aquifer influx, reservoir souring, compaction, subsidence and sand production had to be assessed and contingency measures identified. In addition, the full range of engineering options for the four platforms had to be costed and evaluated. With a planned expenditure of £1.3 Billion, the Brent Field will be able to sustain oil and gas sales well into the next century.
Magic Wand?—Solving the Recovery Problem of a Damaged, Turbidite-Type Reservoir by Horizontal Sections Kicked Off From Existing Vertical Wells
Authors: Werovszky V. P. , Szabari János , Geiger János 
Published: December 2007

Abstract
The number of horizontal wells in the world is steadily increasing. It has often been said that horizontal drilling is mature but in the economically less developed countries this technology nowadays begins to spread. The first successful steps could result in fast growing of this activity especially for gaining additional short term reserves, that is increasing recovery from known fields in these countries and good possibilities at the same time to go into these markets for the drilling companies.
This paper will illustrate in which way the first steps were made in Hungary according to the results of a detailed study about the possibility of using horizontal drilling technology overall in the Hungarian oil and gas production fields.
After ranking and screening the reservoirs, a gas capped low permeability oil reservoir which probably suffered also formation damage during its exploitation was selected first because of its very favourable economic parameters used for comparision and its suitable reservoir conditions.
Polymer Solution Extension Viscosity Effects During Reservoir Flooding
Authors: Hester R. D. , Flesher L. M. , McCormick C. L. 
Published: December 2007

Abstract
Both shear and extensional viscosity properties of a polymer solution must be characterized as a function of macromolecular structure and solvent-polymer interactions if fluid mobility performance during reservoir flooding can be predicted. When the flow rate through a porous medium exceeds a critical value, polymer coils can elongate and produce additional resistance to flow. Extreme extensional flow conditions can increase the fluid's resistance by two or three orders of magnitude greater than that due only to the shear flow field.
The conditions needed to produce high extensional fluid resistance depend upon 1) polymer properties, 2) porous media geometry, 3) fluid flow rates and 4) solvent composition. For a fixed porous medium geometry and flow rate, resistance increases with increasing macromolecular contour length and hydrodynamic polymer coil size. In turn, contour length and coil size depend upon macromolecular structure. Thus macromolecular structure can be adjusted to alter fluid resistance to extensional flow fields.
A Partially Scaled Physical Model of Cyclic Steam Stimulation for Recovery of Oil and Bitumen
Authors: Frauenfeld T. W. J. , Kimber K. D. , Sawatzky Ron , Ridley R. K. , Purewal Gurdeep , Drake Ken 
Published: December 2007

ABSTRACT
Cyclic steam stimulation is the most widely used thermal recovery process for Alberta heavy oils and bitumen. This is a complex process where bitumen production is a result of the interaction of several mechanisms. Such a process may be studied by numerical models and by physical models. Physical models of a petroleum recovery process are a useful adjunct to numerical models. Physical models may be used to validate numerical simulations, and may also be used to study process for which the mathematical formulations are not well defined. A partially scaled physical model was used in this study, in order to evaluate available numerical simulators and to study mechanisms involved in the process.
In order to design and construct a partially scaled physical model of a cyclic steam stimulation, the important mechanisms must first be defined. The approach used was to run partially scaled lab models of the process, each of which scaled different mechanisms, and compare the model results with those of the prototype. This study compared 2 models, one built using the criteria developed by Pujol and Boberg, the other built using criteria developed by Kimber (Kimber #2). The former model scaled the relationship between pressure drive forces and gravity forces, while the latter scaled pressure drive forces and fluid expansion. The experimental results were compared to numerical simulations of both models and of a field scale prototype reservoir.
The experimental and numerical results indicated that gravity, the presence of non-condensable gasses and capillary forces were significant forces influencing oil production in the lab models. Capillary forces were less significant in the field scale simulations. The Pujol and Boberg model produced a better representation of cyclic steam stimulation than did the Kimber #2 model. Fracture dynamics and related effects were not represented. This type of a model is applicable to heavy oil reservoirs where there is sufficient initial fluid mobility to establish injectivity without fracturing.
Equations for Transient Gas Solubility Rates Improve Calculation of Volumetric and Work Efficiencies for Sucker Rod Pumps
Authors: Tebourski Hatem , Doty D. R. , Schmidt Zelimir 
Published: December 2007

Abstract
A correlation for transient gas solubility under pumping conditions has been developed which improves the prediction of volumetric and work efficiencies for sucker rod pumps with gas interference. Due to the reciprocating action of the rod pump, natural gas is forced into solution during the downstroke and out of solution during the upstroke. Throughout the pump cycle, the gas phase never reaches an equilibrium with the liquid phase. This paper presents experimental results quantifying the rate of natural gas solubility into and out of the oil phase under turbulent conditions. A new equation for two-phase volumetric efficiency in sucker rod pumps has been derived using transient gas solubility, gas compressibility, and gas-liquid gravitational separation. In addition, the work efficiency of the pump has also been analyzed using the transient gas solubility equations.
Use of Domain Decomposition for Simultaneous Simulation of Reservoir and Surface Facilities
Authors: Schiozer D. J. , Aziz Khalid 
Published: December 2007

Abstract
The main purpose of this paper is to describe the advantages of using domain decomposition when surface facilities are coupled to reservoirs in simulators. Full-held reservoir models that can handle both reservoirs and surface facilities are needed for accurate performance predictions and optimization. Use of conventional techniques for such models can be very CPU time intensive. For this reason, full-field models are either rarely used or they are simplified by handling surface facilities explicitly. Domain decomposition is useful either as an acceleration techniques to reduce computer time in implicit methods or, in conjunction with the use of different local timesteps in each domain, to improve accuracy of explicit methods. An example is presented showing a comparison of accuracy and CPU time for explicit and implicit methods, with and without domain decomposition. Small subdomains around wells are used to model the interface between reservoir and production facilities, and the rest of the reservoir is simulated with conventional techniques. This approach improves performance of full-field models. The prediction of reservoir performance accurately and efficiently can be accomplished by full-field models that use the domain decomposition technique presented in this paper. A fast full-field reservoir model is an important tool for the simultaneous optimization of the entire production system. The techniques presented here provide an efficient way to handle the coupling of reservoirs with surface facilities.
Prevention of Bit Balling by Electro-Osmosis
Authors: Cooper G. A. , Roy Sanjit 
Published: December 2007

ABSTRACT
Work reported previously has shown that the application of a negative potential to a single point indenter or to a micro roller cone bit reduces the tendency of clays or shales to stick to the indenter or the bit, and thus reduces the tendency of a bit to "ball-up' while drilling. The effect is caused by electro-osmosis, the process by which, in the presence of an electric field, water migrates through the clay towards the cathode, and is liberated as a thin film at the metal-clay interface. This water film prevents adhesion of the clay to the metal of the cathode, and thereby reduces bit balling and increases ROP.
In this paper, we report results of further tests, using both roller cone and PDC drag bits in sizes up to four inches in diameter, drilling in both Pierre and Wellington shales. Making the bit the cathode again reduces the tendency of bit balling, and the rate of penetration is increased, in some cases by 100%. The greatest advantage is obtained at the highest rates of penetration. The power requirements to produce satisfactory results are modest, of the order of 10 Watts at 10 Volts for a four inch PDC bit.
This technique provides a novel method of preventing balling without the use of toxic chemicals, and should be of significant practical importance when applied to the field.
Waterflood/EOR Infill Drilling in Drill Site 9, Flow Station 2 of Prudhoe Bay
Authors: Kwan G. W. , Addie D. L. , Redman S. R. 
Published: December 2007

ABSTRACT
This paper presents an inter-company, multi-disciplinary team effort to evaluate the infill drilling potential in Drill Site 9, Flow Station Two of Prudhoe Bay. The primary focus is on the construction of a 3D, four-component, Todd & Longstaff model for benefit analyses. A four-well drilling program was implemented in January 1993, based on results from stochastic modeling. The benefit estimates were reconciled and reality-checked with surveillance and production data.
Work conducted by Geology, Operations, Drilling, Materials, and Facilities Engineering staff among different companies in the Unit team are also summarized to provide a complete picture of this development drilling planning exercise. Special emphasis is placed upon the effectiveness of multi-disciplinary team work in minimizing costs and managing uncertainties, and the overall efficiency in meeting project deadlines.
In a water-alternating-gas miscible flood, the net recovery of an infill sidewell is estimated to be about 12% of its through-wellbore recovery, dependent on the reservoir description, time at which the sidewell is drilled, flood rate, individual well economic limits and project abandonment timing.
The methodology presented may be applicable in other waterflood/EOR areas of Prudhoe Bay for constructing a screening tool for evaluation of infill drilling opportunities. As long as the simulation results are reality-checked with offset well production, geological and surveillance data, drilling risk can then be significantly minimized with good contingency planning.
Cost-Effective Monitoring of Injected Steam Migration Using Surface Deformation Analysis
Authors: Bruno M. S. , Bilak R. A. 
Published: December 2007

ABSTRACT
Steam injection produces subsurface volume expansion due to increasing temperature and pressure within the injection interval. These subsurface deformations induce measurable surface displacements, including vertical and horizontal movements and tilt. Measurements and analysis of induced surface displacements often provide a cost effective method to monitor the extent and orientation of injected fluid migration patterns over large areas and to monitor subsurface zones of recompaction that may contribute to increased oil production during cyclic steam operations. This paper describes field measurement and numerical analysis techniques used to monitor steam injection processes and describes two case studies demonstrating the practical application of this technology.
Study of a Mature Fireflood: MOCO-T
Authors: Northrop P. S. , Wilson J. L. , Soustek P. G. 
Published: December 2007

ABSTRACT
This paper presents the results of a comprehensive study of Mobil's MOCO-T air combustion project in Kern County, CA. Since initial air injection in January 1960, over 63 BCF of air have been injected, representing over 30 times the estimated pore volume of the burned regions at 500 psig. Cumulative oil production to date is approximately 16.5 MMBO. Recent increases in project maintenance costs, excessive waste gas production and treatment expense, as well as new regulatory limitations on hydrocarbon emissions prompted a review of the technical and economic viability of the project.
The study centered around the estimation of current incremental oil due to air injection, which was derived using several analytical and empirical methods. The relative contributions of other potential recovery mechanisms were estimated analytically. The sum of these predicted contributions matched the cumulative production quite well. In addition to estimating volume of oil produced by combustion, theoretical burn volumes were calculated and mapped for each of six reservoir subzones. These maps were confirmed using well log and field data.
Several economic scenarios, including status quo operation, project expansion, and suspension of air injection, were investigated. Where possible, actual operating cost and revenue data were used.
Coiled-Tubing Completion Procedure Reduces Cost and Time for Hydraulically Fractured Wells
Authors: Harms D. A. 
Published: December 2007

ABSTRACT
A unique completion procedure has been developed to reduce the cost and time to hydraulically fracture wells. In the procedure, coiled tubing is used to replace conventional tubing in most of the operations. This procedure is made possible by a wellhead design that enhances safety and simplifies switching from one operation to the next.
Hydraulic fracturing costs comprise the majority of the total cost for new diatomite wells. Multiple stimulations can be completed in a single day by using coiled tubing to cleanout or place sand plugs which are used to isolate the perforated interval between hydraulic fracture stimulations. This allows significant savings to be realized by fully utilizing the service company's entire minimum daily charge. The coiled tubing also functions as a dead string during fracture stimulations which allows real time monitoring of downhole fracturing pressures.
The new wellhead incorporates two unique ideas: 1) a hammer union tree cap which replaces the conventional flanged tree cap. Integral to the tree cap is a blast joint that provides protection from sand erosion when using coiled tubing as the dead string. The wellhead design enables the tree cap (with attached blast joint) to be quickly and easily exchanged with a fullbore lubricator; 2) a full opening gate valve located between the casinghead and the fracture wellhead. The valve is a safety device that allows any part of the wellhead to be removed while ensuring a completely controlled condition.
Absolute Isolation System Facilitates Successful Post-Gravel-Pack Isolation: Case Histories
Authors: Ross C. M. 
Published: December 2007

ABSTRACT
During the performance of gravel pack operations, fluid loss problems that can compromise the productivity of the well sometimes occur. These fluid losses are experienced during work string and production tubing trips that are made into the well, resulting in the well being left in a fluid-loss condition. When consideration is given to managing this condition during the design stage of the completion, however, the operator can employ a special tool system that has recently been enhanced to address these fluid loss problems.
By using a washpipe attached below the gravel pack service tool and the specialized tool system, the formation interval can be isolated immediately after gravel packing (Figure 1). This system can also eliminate multiple work string trips, which saves job time and further reduces chances for fluid loss.
Two tools that provide a positive mechanical latching of an isolation washpipe assembly and a mechanical release to expand a travel joint for circulating-type gravel-pack operations are now available. The positively-locked absolute isolation system, which has been in use for two years, was developed from a shear-pinned version of the releasable washpipe system.
This paper will describe the tool system and how it can be used in combination with various completion design options to facilitate control of fluid loss and help solve other operational problems that occur during gravel packing. Other new enhancements to gravel pack technology, such as a large bore system for 5-/2-inch [13.97 cm] casing, will also be discussed.