bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Solvent Requirements for Vapex Recovery
Authors: Butler R. M. , Mokrys I. J. , Das S. K. 
Published: December 2007

Abstract
In both SAGD and VAPEX, recovery agents are introduced into the reservoir and these displace oil to horizontal wells located at the base. In each process it is desirable to inject at a pressure equal to or slightly below the pressure of the surrounding reservoir, so as to prevent flow of fluids to outside the recovery pattern.
The pressure in the recovery pattern is reduced by allowing production to draw vapour almost to the production well. The recovery agent that is produced is liquid (water condensate or dissolved solvent). This agent is separated and recycled.
The recycled quantity is about 2–6 tonnes per tonne (t/t) of produced oil for SAGD and 0.3–0.5 t/t for VAPEX. Recycle is much simpler for VAPEX.
The pore volume that contained the produced oil becomes filled with recovery agent either vaporized (steam or solvent vapour) or liquid (water or dissolved solvent). The net requirement of recovery agent is equal to the make-up supplied to the system to maintain operation.
For VAPEX, it is this quantity of solvent that determines the net cumulative solvent-to-oil ratio (NCSOR) before blowdown. Subsequently, during blowdown, a considerable fraction of this net solvent is recovered.
At one extreme the NCSOR is the weight of the solvent vapour that has the same volume as the produced oil. This is usually very small, e.g. 0.02 tonnes of propane per tonne of produced oil. At the other extreme it is the weight of the corresponding volume of liquid solvent and this is much larger, e.g. about 0.5 tonnes of propane per tonne of oil.
In practice the solvent in the reservoir is partly vaporized and partly dissolved in the draining liquid and, as a result, the NCSOR lies between the two extremes. In this paper, this situation is analyzed and experimental results from scaled-model studies are presented. These results show that, with propane as solvent, NCSOR values of about 0.1 to 0.2 may be expected in practice. This range of values corresponds to about 20–30% of the net solvent make-up remaining in the form of vapour.
Reducing Economic Risk in Areally Anisotropic Formations with Multiple-Lateral Horizontal Wells
Authors: Smith J. , Economides M. J. , Frick T. P. 
Published: December 2007

Abstract
Well orientation is critical to horizontal well performance in areally anisotropic reservoirs. A horizontal well, drilled normal to the direction of maximum permeability, will have higher productivity than one drilled in any other arbitrary direction. Currently, horizontal permeability magnitudes and even indications of direction are rarely measured in the field. Based on well performance modeling and economic evaluation, this study attempts to determine the relative attractiveness of horizontal wells with multiple-laterals. The work exposes the economic risk in ignoring horizontal permeability magnitudes and directions and demonstrates the importance of adequate reservoir testing. A new rationalization for multiple-lateral horizontal wells is the reduction of the economic risk associated with poor reservoir characterization in areally anisotropic formations while increasing the incremental net present value (NPV) over single-horizontal wells.
The Point Mclntyre Subsurface Development Team: Field Development Planning With A Multi-Company, Multi-Disciplinary Team
Authors: Pish W. J. , Erickson J. W. , Janes R. W. , Bredar W. L. , Pospisil G. 
Published: December 2007

Abstract
This paper describes the composition, functions, accomplishments and key learnings of the multi-company, multi-disciplinary team that is being used to develop the Point Mclntyre field. Additionally, the team's development of a common geologic description, log model, full-field model, and consensus field development plan is discussed. This paper demonstrates how, under certain circumstances, a multi-company, multi-disciplinary team can offer a cost effective alternative to more traditional joint-owner field development approaches.
Coil Tubing Fishing Operations Utilize a First Time Technique to Strip Over and Recover 9500 Feet of Stuck Slickline Wire
Authors: Forgenie V. H. , Heiberger E. M. , Kelso L. K. , Roeth R. E. 
Published: December 2007

Abstract
Coil tubing was utilized to perform a modified strip over operation and recover 9500 ft. of stuck slickline (0.108 in.) wire. The technique, thought to be an industry first, eliminated the risky option of recovering the wire piecemeal via conventional wireline fishing operations. This paper documents the background that lead to the development of the technique. An operational summary details its implementation and illustrations are included of the special tools and techniques employed.
Developing Countries: No Environmental Regulations Equals Project Stranglehold
Authors: Chailer Jack D. 
Published: December 2007

Abstract
In many developing or newly opened countries, the lack of environmental regulations is more confusing and detrimental to project planning, timing and finance than in those countries with seemingly stifling regulations. A government without knowledgeable, experienced environmental and mineral resource staff presents real challenges to a project. The regulatory uncertainties faced by the petroleum industry as it pursues exploration and development around the globe are sometimes monumental. The interrelationship of international companies, their stockholders, standards organizations, financial institutions, host country governments, and non-government special-interest groups must be determined for each project. Each of these entities can have significant effects on projects. It is, however, in many cases, a country's lack of environmental policy and established, written regulations that is the primary inhibiting element of projects and the planning element with the longest lead time.
Management of A Safety Management System
Authors: Fitts Travis G. , Hignite Jim R. 
Published: December 2007

Abstract
The three fundamental components of a safety system are man, machine, and method (Figure 1). Effective safety systems address the interaction of these components to optimize the capability of the system as a whole. Man is the most critical component in the system because manuals, policies, and procedures (methods) can not and will not alone ensure a safe and healthy operation. Likewise, there are no accessories or guards (machines) that can compensate for a lack of careful attention and competent skill level.
Safety systems should be managed with the aim to help people optimize the system so that everyone benefits (win/win).
Integrated Three-Dimensional Seismic and Three-Dimensional Reservoir Flow Simulation Exposes the Effects of Faulting on Coal Gas Production at Cedar Hill
Authors: Heim R. N. , Van Kirk C. W. 
Published: December 2007

Abstract
This study used an integrated approach to characterize the Cedar Hill field, a naturally-fractured coalbed methane reservoir, through use of a three-dimensional flow model, three-dimensional multicomponent seismic survey, and detailed engineering and geologic analyses. Results indicate that faulting influences reservoir production and illustrate the importance of a multidisciplinary approach in the characterization of coalbed methane reservoirs.
Geophysical techniques were used to locate previously unrecognized structural features and zones of higher pressure indicating inadequately depleted portions of the reservoir. Petroleum engineering and simulation techniques verified and quantified reservoir parameters, such as faults, identified from seismic interpretation. The integration of geophysical, engineering, and geological data accelerated the study and increased the accuracy of the reservoir model leading to a better understanding of production controls at Cedar Hill.
Qaharir Field, Oman: A Textbook Case
Authors: O’Dell P. M. 
Published: December 2007

Abstract
Qaharir Field is located in the southern part of the Sultanate of Oman. Like several fields in South Oman, it produces a light oil with very little solution gas. Qaharir Field contains a large depletion reservoir and several natural water drive reservoirs. There is, therefore, a large variation in the primary recovery efficiencies. A recent petroleum engineering review of this field deternined the reservoir drive mechanisms and provided a basis for further development plans. This review of Qaharir Field demonstrates the application of conventional reservoir engineering tools to gain an understanding of the reservoir in sufficient detail to select and plan the next development objectives.
Immiscible Displacement Mechanisms and Scale-Up in the Presence of Small-Scale Heterogeneities
Authors: Saad Naji , Cullick A. S. , Honarpour M. M. 
Published: December 2007

Abstract
Relative permeability and capillary pressure functions determined from laboratory core floods must often be scaled-up for assignment to reservoir simulation models used in performance prediction. Conventional scale-up methods do not take into account the heterogeneities at the lithofacies scale, and use core plug measured relative permeability and capillary pressure data in the calculation of effective properties for use in flow simulation. This may not capture the true two-phase flow behavior in the reservoir. The displacement mechanisms encountered in reservoir rocks at the lithofacies scale with small-scale heterogeneities may be very different from displacements in core plugs of the same rock. This paper discusses the immiscible displacement mechanisms in the presence of small-scale heterogeneities at the lithofacies scale. Our aim was to characterize the displacement mechanisms during steady-state flow at different fractional flows and during unsteady-state flow as related to scale-up issues.
The extensive experimental data used in this study consisted of imbibition and drainage data from steady-state tests and from waterflooding measurements on a 108 cm long, laminated rock sample; relative permeability and capillary pressure measurements on core plugs cut parallel and perpendicular to the crossbedding; in situ saturation data measured during flooding using linear x-ray and x-ray CT scanning; and pressure measurements at the inlet/outlet and along the rock sample at various locations.
Numerical simulation was used to history match the laboratory waterflood test. Validated numerical model was used to investigate displacement mechanisms and scaling laws at different fractional flows. Experimental results from the imbibition and drainage test for the long core and the core plugs were compared and flow simulation was used to investigate the use of core plug data at the lithofacies scale.
The Calculus Of Common Sense
Authors: Grayson C. Jackson 
Published: December 2007

The president of a major oil company was recently quoted in The Oil and Gas Journal, as saying that today's circumstances require every oil-company management to "face up to reality and begin making more hard-headed decisions" (italics mine) regarding its day-to-day operations and future capital investment policies. The reasons he cited were the slowed rate of growth in demand and overcapacity in nearly every phase of oil operations. Judging from similar remarks by others in the industry, it appears that the future success of the industry, and particularly, that of individual companies, is going to depend on wise courses of action, or as he puts it, "hardheaded decisions."
I agree. In this paper, I want to talk about such hard headed decision making. What really is a decision? How does one go about collecting information, naming alternatives, assigning gains and losses from alternative actions, formulating criteria, selecting one action? It is difficult enough under conditions of relative simplicity and certainty, but when the decision is complex and the outcomes highly uncertain, the problem is compounded.

DECISION PROCEDURES
In such a situation, a decision maker generally follows one of three courses:Decides solely on the basis of intuition, judgment, hunch, seat of pants, experience, etc.. This is decision making as an art.Decides on the basis of simple, quick calculations and "reasonedjudgment." This is mixed art and scientific thinking.Decides on the basis of some fairly detailed and rigorous procedure, capturing as much information and judgment as possible in mathematical and statistical language so that it may be studied and manipulated by formallogic.
The last decision procedure is what can be called hard-headed decision making. It is what academic people are referring to today as "decisiontheory."
Optimization of Lean Gas Injection in Gas-Condensate Reservoirs
Authors: Pires A. P. , Correa A. C. F. , Mohamed R. S. , Sousa R. 
Published: December 2007

Abstract
In gas-condensate reservoirs, a major challenge is to avoid the drop-out of the heavier fractions, which represent the rich part of the gas, responsible for great part of its heat capacity and, consequently, its price.
A widely used prattice to keep the reservoir fluid above its few point pressure is the injection of produced lean gas into the reservoir. This technique is known as gas cycling. As the lean gas is injected in the reservoir, the overall fluid composition is changed and so does its dew point and phase envelope. Furthermore, the rate of pressure decline fo the reservoir depends on the fraction of the produced gas being injected.
We present a coherent thermodynamic analysis of the effects of lean gas injection fo two Brazilian gas/condensate reservoire through the determination of the phase behavior of injected/original gas mixtures.
The accuracy of the thermodynamic model employed is verified through the comparison of the model predictions with laboratory data.
The results obtained from this analysis are used to determine the maximum amount and optimal composition of lean gas to be injected fo a gas/condensate reservoir in onler to change its composition and shift the phase envelope to a point where the liquid droprout can be eliminated or minimized during the isothermal deletion of the reservoir.
The results can also be used to optimize the operation of gas pipelines and production equipment and facilities.
Controlling Formation Damage Caused by Kaolinite Clay Minerals: Part I
Authors: Hayatdavoudi A. , Ghalambor A. 
Published: December 2007

Abstract
During petrophysical and petrographical analyses of the core plugs, generally, we pay close attention to the "fines migration" when we observe kaolinite minerals filling the pore space or lining the pores. The conditions leading to a drastic reduction of permeability (formation damage), at low temperature, by kaolinite have been documented in the literature: (1) to depend on the colloidal and hydrodynamic forces far from and near the well bore respectively and (2) to mechanically bridge the pore throats. And, at high temperature like in steam flooding, the formation damage caused by kaolinite depends on (1) water chemistry i.e. ionic content, (2) pH of the injection water, and (3) low salt concentration. Although these mechanisms provide a general knowledge base to control the formation damage by controlling the kaolinite particles we found no clues as to what changes occur in the kaolinite morphology or mineralogy. The case in point is a Tuscaloosa sand core from central Louisiana while being drilled with a high pH fluid i.e. pH=10-12 with caustic soda.
In order to understand and therefore to control the formation damage due to kaolinite migration, we subjected a series of core plugs prepared from a Tuscaloosa sand conventional core to a low temperature, high simulated spurt loss (flow rate of 11.1 cc/min) for a short period of fluid/rock contact time (45 minutes). After a thorough petrophysical analysis, we found that within this short period of contact time between the rock and fluid at pH=10-12 at low temperature, the permeability of cores decreased considerably. The petrographical analysis of the same cores revealed that the reason for this drastic change in permeability was the onset of the conversion of kaolinite to hallovsite and dickite under the oxidative effects of Sodium Peroxide. Also, the amphoteric nature of kaolinite similar to Al(OH), i.e. dissolution of kaolinite in both acids and bases, plays an important role in its solubility in caustic soda at pH=10-12.
On the basis of our findings we concluded that in both field and laboratory coring and/or drilling the Tuscaloosa sand or possibly any other sand with a high kaolinite content (greater than 5%) the best conditions for controlling the formation damage are to keep the pH of all injection fluids in a buffered and well controlled state of near neutral and/or to control the filtrate to near zero in such sensitive formation.
A New Model for Formation Damage by Particle Retention
Authors: Nabzar L. , Chauveteau G. , Roque C. 
Published: December 2007

Abstract
The formation damage caused by the injection of water containing suspended particles, which are stable and are not adsorbed spontaneously onto pore surfaces under Brownian motion, has recently been analyzed at a pore scale level. Formation damage is the result of four more or less overlapping successive steps:deposition on a grain surface,formation of mono- or multiparticle bridges with subsequent accumulation upstream from the bridges,internal cake formation as soon as the nonpercolation threshold has been reached near the core entrance, andexternal cake formation.
The surface deposition is not uniform over the grain surface and varies from the upstream stagnation point to the near pore throat zone according to a function depending on flow rate and surface forces. The bridging of pore throats is strongly dependent on the effective pore throat-to-particle size ratio, and the pore-throat size is often reduced by previous surface deposition.
A new model has been developed to predict formation damage while taking into account these different steps. The dominant mechanism in each step is governed by parameters that have a clear physical meaning. However, due to the complexity of natural systems, these parameters cannot be quantitatively predicted from theoretical considerations but can easily be determined by specifically designed lab experiments. The model predicts the retention by deposition, by bridging and by subsequent accumulation upstream from bridges, the concentration in flowing particles and the local permeability reduction as a function of the distance from the inlet, as well as the overall permeability reduction, and the beginning of external cake formation.
This new model appears to be an effective tool for analyzing the consistency of a set of laboratory data and for selecting the values of the parameters that must be introduced in a near-well bore field simulator for the proper prediction of formation damage in a given application.

Introduction
The early models proposed in the oil literature aimed to fit the decrease in relative permeability observed when a particle suspension is injected into a permeable core. Thus these models are empirical or at best purely phenomenological in the sense that they simulate observed phenomena by using equations without any clear physical meaning. They are very attractive however for petroleum engineers since they are very simple and easily introduced in conventional field simulators without increasing computing time too much. A good review of these empirical models can be found in Ref. 1.
An Overview of HF Acid as Applied to the Wilcox Sand in Reddell Field, Southwest Louisiana
Authors: Guichard J. A. , Allison David , Gdanski R. D. , Ghalambor A. 
Published: December 2007

Abstract
The Wilcox reservoir in South Central Louisiana's Reddell Field has responded quite favorably to slow-reacting HF acid treatments. A historical perspective, dating back to 1981, is the basis for the comparison of traditional HF acid (12% HCl – 3% HF) systems to that of the slow-reacting HF acid system. These documented benefits are listed below:Two-to four-fold production increaseAccelerated recovery of well productionReduced workover fluid recovery time from 24 months to 2 monthsIncreased success rate associated with stimulation from 40% to 90%
The improved performance was achieved because of careful attention to reducing chemical incompatibilities. Separation of the HF fluids from the potassium chloride workover fluids and the proper choice of HC1-HF concentrations for the Wilcox formation mineralogy dramatically reduced secondary plugging from the HF treatment.
This paper discusses Wilcox formation mineralogy and its susceptibility to formation damage. In addition, the paper compares conventional acid treatments to slow-reading HF acid treatments. Finally, criteria are suggested regarding applications of HF acid for similar formations.
Water Flooding Facilities Salem Unit, Marion County, Illinois
Authors: Livingston Rex L. 
Published: December 2007

Introduction
The Lake Centralia-Salem Oil field, Marion County, Ill. was formally unitized September 1, 1930 for simultaneous water flooding of five pay horizons. The engineering and operational aspects of the formation of the Salem Unit have been discussed by Love. Geology of the field has been presented by Arnold. The unitized field embraces an area of 8,800 acres approximately 6 1/2 miles in length and 2 1/2 miles in width. The field has produced 222,000,000 bbl of oil while some 15,000,000 bbl remain to be produced by primary methods. It is estimated that the ultimate secondary oil recovery will be approximately 85 per cent of that recovered under primary production.
The magnitude of this project may be appreciated when it is realized that accumulated injected water will be of the order or 1,680,000,000 bbl during a 20 year flood life. At peak conditions the total injection requirements may reach 350,000 B/D.
The proper selection of surface facilities for a project of this size presents a multitude of complex problems. Careful consideration must be given to the economic aspects of each phase, not only in equipment and construction, but also from the standpoint of operational costs. It is the purpose of this paper to present a discussion of the equipment and facilities that have been installed in the Salem Unit to accommodate the secondary recovery operations.
Figure 1 shows a diagrammatic flow plan of flooding facilities.

Water Supply
The field was producing approximately 8,000 B/D of salt water at the time of unitization. It was estimated that a maximum water injection requirement of nearly 350,000 B/D would be reached during life of the flood for all formations. Considering time for flood development, field water production, etc., it was further estimated that make up water of approximately 185,000 B/D would be needed to meet this requirement. Extensive investigations were conducted in the immediate and surrounding areas of the Salem Pool to determine the most satisfactory source of water.
From these investigations it was concluded that the most economical source of water would be from fresh water gravel terrace deposits along the Kaskaskia River approximately 17 miles northwest of the field. In these investigations, consideration was also given to the possibility of developing a salt water supply from aquifers of 1,000 ft to 1,500 ft depth in field area, but the economics of such a source were not favorable because of the large anticipated volume requirements. It was estimated that development and operating costs of the fresh water source to produce 185,000 B/D would be about 60 per cent less then that of the salt water source.