bluuebunny/crossref_metadata_2025_split huggingface dataset:
About Kinds of Breakthrough and Maximum Recovery Factor in Dual Coning
Authors: Pietraru V. , Le Bars Ph. 
Published: December 2007

Abstract
A new analytical method of gas and water coning evaluation for horizontal (H) and vertical (V) wells is presented. In dual coning there are five kinds of breakthrough (BT). Both gas and water apex have a parallel evolution and this fact is very important for behaviour of recovery factor (RF). Then analytical correlations for RF are presented followed by examples of calculation. RF depends mainly on well position (and its perforation), oil rate, anisotropy and capillarity.

Introduction
The most remarkable papers on coning phenomenon are Muskat and Wickoff, Sobocinski and Cornelius, Bournazel and Jeanson and Weiping and Wattenbarger. The main sources for analytical solutions are classical books by Carslaw and Jaeger and Muskat and recently books by Chaumet and Streltsova.
Pietraru and Cosentino published in 1993 a new fully analytical approach. This method has been generalized and extented for dual coning. Muskat and Wickoff (figs. 4 and 5) was the source for the new concept of "radius coning". The references, were used for analytical solution of diffusion equations, with various boundary conditions.
This paper presents briefly the new method, after references, then presents criteria for different kinds of breakthrough and new correlations for recovery factor (actual and maximum) in dual coning.

Dual coning

Correlations for dual coning parameters
Fig. 1 presents a geometrical scheme for dual coning. Main hypothesis is that gas oil contact (GOC) and oil water contact (OWC) are influenced by one well only (no interference). Dupuit's hypothesis is accepted (when the vertical flow composants are neglected). The pressure drop controls both gas and water apex and if gas-cap and aquifere are very strong the pressure drop in gas and water are neglected. Then the heights of apexes are given by the following expressions:
(1)
(2)
where po is the pressure drop in oil between the initial pressure and the pressure at the apex. In this condition both height of gas and water apexes are directly proportional to the po and inversely proportional to density difference. Constant C1 depends of unit system (see Table 1).
Coning Radius. Pietraru proposes the new concept of "coning radius" and its empirical expression:
(3)
The radius coning is a very important parameter. It defines the value of abscissa controlling the critical coning height.

Correlation of oil rate versus time of BT
Fig. 2 presents the main correlation of dimensionless rate as function of three dimensionless parameters (see Appendix A)
(4)
General solution. A new solution is given with the hypothesis that the oil rate is the sum of three terms: first term is the rate of an horizontal drain (with length 4, see appendix A) and both second and third terms are equal to half rate of V well.
P. 169
Underbalanced-Directional Drilling with Coiled Tubing - Challenges and Solutions
Authors: Scherschel S. R. , Graves D. G. 
Published: December 2007

Abstract
The inherent advantages and limitations of drilling with coiled tubing have been the subject of many presentations in the last several years. The potential benefits that coiled tubing drilling systems offer have prompted development of several competing systems that are now being brought to the market. Although each of these approaches share some similarities, unique features have been introduced that enhance the value of the available systems.
Full exploitation of coiled tubing drilling systems dictate that a practical approach be taken. Specifically, the most attractive approach is the one most highly leveraged to deriving the benefits offered by using coiled tubing. Because the coiled tubing drilling system is subject to limitations with respect to force delivery and the inability to rotate, the application of this emerging technology needs to be directed to a niche where it provides the operator best value.
Coincident with the developments in coiled tubing drilling, industry's acceptance of underbalanced drilling techniques has been growing. It is now widely understood that the advantages of coiled tubing drilling are most evident in underbalanced operations. These advantages of technology will be applied to a wide range of well-finishing and re-entry operations to increase both the productivity and recovery of hydrocarbons from existing fields.
This paper presents the latest technology being applied in underbalanced coiled tubing drilling operations and highlights the additional advantages of using a pressure deployment system. Operations conducted in the first ten months of 1996 using these tools are reviewed.
Pressure Transient Analysis for Horizontal Well and Multi-Branched Horizontal Wells
Authors: Kong X.Y. , Xu X.Z. , Lu D.T. 
Published: December 2007

Abstract
Transient pressure for cases of a horizontal wellbore axis with any angle inclined to a fault or a constant pressure supply boundary in anisotropic formations were studied. This axis parallel to or perpendicular to a fault is only its a simple special case. Particularly, the cases of multi-branched horizontal wells and horizontal well in pinch angle (wedge angle) were developed.
The table of the analysis solutions of transient pressures for various arrangements of horizontals are provided. The wellbore pressures took into account wellbore storage coefficients and skin factor are handled by the help of Laplace transforms.

Introduction
Transient pressure analysis for horizontal wells have presented in several publications, Refs. 1–20. These literatures considered the cases of horizontal wellbore axis parallel to a fault, a horizontal well in infinite formation and in rectangular bounded formations (box-shaped drainage, well parallel to or perpendicular to side faces), respectively.
In this paper, we first give the line source solutions with no wellbore storage and no skin for cases of horizontal wellbore axis parallel to or perpendicular to a fault or constant pressure supply boundary. Then we present the line source solution of multi-branched horizontal wells, i.e. drilling several horizontal wells with various directions from main vertical well. It is equivalent to a horizontal well in a pinch angle in certain conditions. The line source solutions for a definite problem are based on the use of source and Green's functions. Then we take into account wellbore storage and skin used Laplace transforms. A table of Green's functions of transient pressures was prepared in this study for multi-branched horizontal wells and horizontal well in pinch angle (wedge angle) as well as horizontal wells near a fault or constant pressure boundary.

Physical Model and Governing Equations
The model considered in this study is assumed as followingThe fluid is slightly compressible, its viscosity and compressibility c1 are constants.The formation is horizontal and equal in thickness h.The well is assumed to be parallel to the top and bottom which may be impermeable or constant pressures, to be locate at any location, zw, from the bottom, its length is 2L.The formation is anisotropic system with KH KVGravity effects are considered to be negligible.
The equation governing flow is the diffusivity equation as derived from the continuity equation, an equation of state, and Darcy's Law
(1)
where p(x,y,z,t) is pressure, and
(2)
in Eq. (2) c is total compressibility.
Horizontal Wells near a Fault or constant Pressure Boundary
Horizontal wells parallel to a fault
For a horizontal well parallel to a linear fault, the x-coordinate direction is oriented along he horizontal wellbore axis, z-coordinate direction upward vertically. P. 285
Formation Damage from Workover and Completion Fluids
Authors: Eaton Ben A. , Smithey Mack 
Published: December 2007

Abstract
Wellbore damage that occurs during initial well completion or workover operations is the subject of this paper. The linear and radial fluid flow equations are reviewed in relation to this problem and in relation to the laboratory procedures used to test for such damage. procedures used to test for such damage. Return permeability testing methods are discussed, as are the results of such tests. Several commonly used completion and workover fluid systems were compared and these comparisons are included.
The merits of the relatively new and almost nondamaging systems are given. Several cases of their application are discussed in the form of field case studies.

Introduction
A subject that has received a great deal of attention in recent years is that of formation or skin damage around a wellbore. Most of this attention has been directed to the problem of skin damage caused by drilling and cementing productive zones. Such damage normally is of a productive zones. Such damage normally is of a shallow penetrating nature and good perforating, stimulating and completion practices overcome much of the problem. However, poor completion and workover fluids and practices may cause considerable damage to a formation long after the formation was drilled, cemented and perforated. The damage to producing formations caused by workover and completion fluids is the subject of this paper.
Many forces tend to change the natural virgin permeability of producing formations during initial completion and/or workover operations. The net result is usually a reduction in permeability in the vicinity of the wellbore or perforations, and a decreased ability of a well to produce.
Operations considered here to be completion or workover functions include the following: perforating casing, under-reaming pay zones for perforating casing, under-reaming pay zones for gravel-packing, under-reaming injection zones for gravel-packing for disposal purposes, gravel packing, plastic sand consolidating, all workover packing, plastic sand consolidating, all workover operations in which a producing zone must be killed, all workover or completion operations in which wellbore fluids are lost to the formation and drilling into a pay zone after casing has been set on top of the zone.
A New Intelligent Computer System for Horizontal Wells Gravel-Packing
Authors: Pu Chunsheng 
Published: December 2007

Abstract
A new mathematical and intelligent computer system for the optimal design of horizontal wells gravel-packing was developed. The mathematical models in this computer system were established by the use of non-Newtonian fluid flow and fluid-solid two phase equilibrium characteristics in the tailpipe-screen annulus and the open channel above an equilibrium bank of the horizontal well. A new propagation algorithm based on Grey and fuzzy theory was used to construct the inference engine of the computer system to give the sanding potentials assessment of a poorly lithified or uncemented sandstone formation. This computer system can be used to predict the flow velocity of the carrying fluid, the pressure distribution of the flow field, the concentration distribution of the gravel sand and the packing efficiency. So, this system can be easily used for the optimal design of horizontal wells gravel-packing. A practical application example was introduced and rather satisfactory results were obtained.
Correction Routines for Production Logs in High Productivity Wells with Open Hole Completions and Screens
Authors: Mustad D. , Berg K.B. , Haheim S.A. 
Published: December 2007

Abstract
A number of production logs in the Troll Oil production wells have been performed. Horizontal screen sections up to 2000 m required logging tool deployment by coiled tubing. All wells flowed monophase oil. Practical correction procedures for the logs are proposed. The corrections cover annular flow between screen and open hole, coiled tubing displacement flow, coiled tubing influence on drawdown and productivity due to reduced flow area. The correction procedures are essential for interpretation of individual layer productivities, which is demonstrated on field examples.

Introduction
The Troll Oil field is located in 300 m water depth offshore Norway. The field is characterized by a thin oil zone (13–26 m) sandwiched between a large gas cap and active aquifers. The reservoir contains several highly permeable unconsolidated sands separated by low permeability micaceous sands. Impermeable calcite layers occur within the high permeable sands. Several publications describing the Troll Oil horizontal well development are available.
The production logs performed on the Troll oil wells had two main objectives:verify cleanup of the well after setting of kill pill,determine the productivity and permeability profiles along the well.
In long horizontal wells with small drawdowns (a typical value during logging at 2000 Sm3/d of the Troll Oil wells is 0.2 Bar), the production log analysis is not straightforward, and a number of corrections to the measured data must be performed to obtain representative production inflow profile along the completion interval. The most important corrections identified for the Troll Oil wells are (1) coiled tubing displacement flow, (2) coiled tubing influence on drawdown and productivity due to reduced flow area, and (3) annular flow between screen and open hole. In addition water or kill fluid accumulation at low points in the well may corrupt the spinner flowmeter response. This paper discusses possible methods to correct for these effects. A possible disturbance of the velocity profile in the screen due to radial inflow has not been accounted for.

Mathematical Modeling
Fig. 1 and 2 show the flow in the screen section with and without coiled tubing present. To understand the influence of the coiled tubing mass and momentum balance of a horizontal well section with and without a coiled tubing is required. The analysis is similar to that performed by Dikken, with the addition of the acceleration pressure drop and the coiled tubing effects.
Mass Analysis. From Fig. 3 the following mass balance equations are obtained for a control volume with coiled tubing partly inserted
(1)
or, equivalently,
(2)
For a control volume without coiled tubing we get
(3)
P. 699
Production Optimization Of Re-Entries By Means Of Electrical Submersible Pump
Authors: Joubert G. , Brito H. , Yibirin J. 
Published: December 2007

Abstract
This paper presents the results of the optimization process carried out in wells JOM-38, JN-3, CD-l and CC-7 located in the Jobo and Cerro Negro Fields, using horizontal drilling techniques and electrical submersible pumping as a lifting system.
These wells originally had been drilled vertically, in an unconsolidated formation of reservoirs with strong water drive, obtaining initial oil production rates in the order of 250 STB/D of 8.5 API and 2500 cP at reservoir conditions. However, because of the adverse mobility ratio, the oil production dropped drastically with time and water production increased substantially (less than 50 STB/D and 85% water-cut) making these wells uneconomical.
Due to the low performance, the wells were re-entered with an average horizontal sections of 1550', obtaining production rates in the range of 350 - 500 BOPD/well using progressing cavity pumps as means of artificial lift. These rates were still below the expected 1000 BOPD predicted.
In view of these results and considering the high productivity index measured in these reentry wells, a pilot project was developed, changing the existing lifting system for an electrically driven submersible pump. The new production rates thus obtained varied from 700 to 1300 BOPD/well, with a watercut in the order of 10 percent.

Introduction
Venezuela possesses one of the largest heavy crude oil and bitumen (8.5 - 9.0 API) accumulation in the world; located in the Orinoco Belt region and Jobo field.
Heavy and extra-heavy oils have been traditionally produced by means of vertical wells with sucker rods as the lifting system, achieving a cold production of up to 250 STB/D.
In the last years, new technologies have been applied in the oil industry to optimize oil production. A combination of horizontal well and lifting methods such as sucker rods, screw pumps and electrosubmersible pumping have been evaluated to determine an efficient and economic way to exploit the huge heavy oil reserves.
Among the lifting methods, electrosubmersible pumping seems to be an attractive system to produce heavy oil wells with high productivity index (able to produce more than 1000 STB/D).
Four horizontal re-entries with high productivity index (two in Jobo field and two in Cerro Negro field) were selected for electrical submersible pump installation, obtaining substantial increase in production.
The pilot test was carried out injecting diluent (diesel refinery cut) at different rates and monitoring the dynamic fluid levels while the pump frequency was increased from 40 to 60 Hz. In this paper, the results of the tests are presented.

Geographic Location.
Wells JOM-38, JN-3, CD-1 and CC-7 are located in the Jobo and Cerro Negro fields in the Eastern part of Venezuela just North of the Orinoco river at Monagas State (Figure 1).
P. 817
Is There a Correlation Between Wettability From Corefloods and Contact Angles?
Authors: Rao Dandina N. 
Published: December 2007

Abstract
Laboratory coretloods have constituted a major step in understanding many aspects of fluids flow behaviour in reservoirs. The reservoir rock samples, having been retrieved from the oil-bearing formations, have been most valuable since they represent the actual solid phase of the reservoir rock-fluids system in laboratory studies. Therefore, it is only natural that we try to maximize the information that can be extracted from these cores and corefloods Oil-water relative permeabilities are perhaps the most widely derived parameters from such corefloods and they are the only recourse to account for all the rock-fluids interactions in the mathematical models developed to describe the reservoir flow phenomena Thus, coring, core preservation, core analysis, core flooding, and coreflood data analysis have formed the basis of our knowledge on reservoir fluid mechanics.
One of the factors that has a strong influence on reservoir fluid mechanics is rock wettability. Therefore, attempts to derive wettability from corefloods are abundant in the literature that spans several decades. On the other hand, contact angles observed in crude oil-water-solid systems have been traditionally regarded as a true or universal measure of wettability. Hence the obvious question - is there a correlation between wettability derived from corefloods and contact angles?
A definitive answer does not seem to emerge from the literature for two main reasons: (1) Craig's broad rules-of-thumb, while enabling approximate comparisons especially between extreme cases of wettability, do not allow direct deduction of rock-fluids interactions to the extent that is required to characterize wettability, and (2) the conventional contact angle measurements have had their own share of problems in terms of reproducibility. The dual-drop-dual-crystal (DDDC) contact angle technique, recently reported in the literature1, appears to resolve this long-standing repr- oducibility problem with contact angle measurements. This presentation aims to compare wettability derived from reproducible DDDC tests in widely differing rock-fluids systems with their corresponding oil-water relative permeabilities derived from waterflood experiments using reservoir and Berea cores In all, a total of six different case studies are compared in which four rock-fluids systems appear to yield similar wettabilities from corefloods and contact angles while the others differ markedly Explanations are sought for these agreements and differences in an effort to shed more light on this important aspect of correlating core analysis with distribution and flow mechanics of reservoir fluids.
Onset Crystallization Temperature and Deposit Amount for Waxy Crudes: Experimental Determination and Thermodynamic Modelling
Authors: Calange Sandra , Ruffier-Meray Véronique , Behar Emmanuel 
Published: December 2007

Abstract
Paraffinic crude oils are often transported at conditions where heavy hydrocarbons contained in the oil may precipitate as a solid waxy material. This precipitation may plug the processing equipment. In the design of oil production facilities, it is therefore essential to be able to predict the conditions where wax crystallization may take place and the amounts of wax which may form. Several models have been proposed in the literature for the prediction of wax precipitation from natural crude oils. But they generally overestimate considerably the amount of wax precipitation below the wax appearance temperature (WAT).
The objective of this study has been to develop a reliable compositional thermodynamic model to compute wax appearance temperature as well as the amount and the composition of waxy deposits as a function of temperature and to verify the proposed model with experimental results. This paper will describe the thermodynamic model and the complementary laboratory test methods. The agreement between the measured and predicted values for two crudes of different production areas is good.
PARA-Based (Paraffin-Aromatic-Resin-Asphaltene) Reservoir Oil Characterizations
Authors: Leontaritis Kosta J. 
Published: December 2007

Abstract
Conventional, carbon number compositional analysis techniques provide the weight or mole fraction of pure components up to Cg-and carbon number pseudo-components that represent the C7+ fraction. These typically reported carbon number oil compositions cannot be used with asphaltene and/or wax phase behavior models and are not suitable for interpretation of experimental asphaltene and wax studies, because they do not provide direct phase compositional information on the waxes, resins, and asphaltenes. Waxes, resins, and asphaltenes are usually distributed among the heavier carbon number pseudo-components in these carbon number-type compositional analyses. Hence, new techniques and methodologies are required for analyzing hydrocarbon fluids for the amount and type of waxes, resins, and asphaltenes and for developing EOS oil characterizations suitable for predicting PVT, wax, and asphaltene phenomena. This will eliminate the traditional guess-work that is involved in the development of EOS oil characterizations of asphaltenic and/or waxy fluids.
A new, efficient, and more accurate technique for analyzing crude oil and its fractions to determine hydrocarbon group types, i.e., paraffins (including paraffin waxes), aromatics, resins, and asphaltenes is the PARA analysis. Distillation, solvent extraction, high performance liquid chromatography (HPLC), gel permeation chromatography (GPC), and other techniques are used to perform the oil analyses and obtain the compositional and structural data required for characterizing each hydrocarbon group with its individual pseudo-components. The analyses, in addition to providing weight and/or mole percent for each fraction, provides a starting a priori oil characterization suitable for EOS type modeling methods. The starting oil characterization includes an experimentally assisted selection of pseudo-components for each hydrocarbon group type together with an initial estimate of their critical properties, molecular weight, and acentric factor. This paper discusses the PARA-Based (Paraffin-Aromatic-Resin-Asphaltene) EOS reservoir fluid characterization technique and presents an example application of PVT and wax phase behavior modeling.