bluuebunny/crossref_metadata_2025_split huggingface dataset:
All Purpose Cement-Mud Spacer
Authors: Beirute Robert M. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Society of Petroleum Engineers of AIME Symposium on Formation Damage Control, to be held in Houston, Tx., Jan 29–30, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
This paper deals with the problem of formation damage generated by high pressure differentials between annulus pressure differentials between annulus and formation during cementing. Specifically, the elimination of viscous cement-mud mixtures by the usage of a water external (oil in water), temperature stable emulsion spacer is presented. presented. Careful attention is given to the preparation of the casing and well bore preparation of the casing and well bore surfaces by the spacer, prior to cementing. Lab and field results clearly show that cement bonds best to a waterwet surface created by the water external spacer.
The effect of contamination on fluid loss control of well fluids is presented. Other tests indicate that cement strength is less affected when contaminated with a water external emulsion spacer than when contaminated with oil base fluids.

Introduction
Mud displacement mechanisms, spacers and problems created by the contamination of cement by drilling muds have been discussed previously in the literature. However, in this paper we take a closer look at spacers from the point of view of formation damage control and cement bonding.
Formation damage can be caused by drilling fluids during drilling operations, but further formation damage can occur during cementing operations. The fluids and solids lost from slurries can cause damage by entering the formation and reducing its permeability.
The amount of fluid lost from a cement slurry into a formation depends on several factors, including the pressure differentials occuring during pressure differentials occuring during cementing. The higher the pressure differential into the formation, the more fluid will be lost to the formation.
A Review of Hydroxy-Aluminum Treatments
Authors: Haskin C.A. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Society of Petroleum Engineers of AIME Symposium on Formation Damage Control, to be held in Houston, Tx., Jan 29–30, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate Journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with this paper, may be considered for publication in one of the two SPE magazines.

Abstract
Hydroxy-aluminum chemical (OH-Al) has been used in hundreds of wells to sustain production by stabilizing clays that cause permeability damage and well sanding. Commonly used in conjunction with other well stimulation processes OH-AL has prolonged the stimulated production response and extended the life of producing equipment.
Among the many successful treatments have been some failures, however, the number of failures have been small relative to the number of successful OH-AL treatments that have been done. Mechanically damaged wells, downhole placement problems, poor job design, and failure to consider the limitations of the OH-AL chemical have been the primary causes of failure among most of the unsuccessful treatments that have been reported.
Correct well diagnosis and good job design can significantly reduce the risk of job failure regardless of the type of well treatment involved. Understanding how OH-AL interacts with the formation clay minerals helps determine when and where the chemical might be used most effectively. Recognizing the effect of chemical incompatibility, temperature, and OH-Al concentration on treatment results is essential for optimum job design.

Introduction
Several hundred wells in the industry have been treated with clay stabilizing hydroxy-aluminum (OH-Al) chemical since the technology was introduced in 1971. Figure 1 shows the number of wells treated with OH-Al chemical through 1974. The majority of treatments have been done in oil wells, but gas wells and water injection and source wells have also been successfully treated. Most OH-AL treatments have been done for (1) sand stabilization, (2) sustaining production following acid stimulation, and (3) stabilizing clays ahead of steam stimulation and water injection.
Application of SSOR to Three-Dimensional Reservoir Problems
Authors: Wattenbarger R.A. , Thurnau D.H. 
Published: December 2007

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

Abstract
A relaxation method called Slice Successive Overrelaxation has been developed for the solution of matrix problems occurring in three-dimensional reservoir simulation. The SSOR technique represents a significant improvement over previously used techniques and is considered to be a general method.
The mathematics of SSOR is a straight-forward extension of block SOR techniques in which the submatrix, or block, corresponds to a vertical plane (slice) through the reservoir. This technique has become practical by the application of a reordering practical by the application of a reordering scheme to the direct solution of each submatrix. On iterations subsequent to the first, the forward elimination on submatrices is not required, making succesive iteratons comparable to LSOR in speed. The Watts correction method is applied in its generalized manner similar to LSOR and dramatically enhances the speed of convergence.
Test results are shown for various reservoir problems. The method is shown to be particularly advantageous in a typical three-dimensional problem where vertical permeability barriers exist in portions of the permeability barriers exist in portions of the reservoir and high vertical transmissibilities occur elsewhere. It is demonstrated that the convergence rate of applying SSOR to a three-dimensional problem is essentially the same as the convergence rate of applying LSOR to the two-dimensional projection of the same problem. A method is presented which can be used to estimate the computer time required for an SSOR solution.

Introduction
One of the persistent problems in reservoir simulation is that of solving the matrix problem which arises from the "pressure problem which arises from the "pressure equation." Over the years, a number of methods have been developed and utilized with success for various types of problems.
For most reservoir simulation problems, we find that the solution of the matrix problems, we find that the solution of the matrix problem is very efficient and represents problem is very efficient and represents only a minor part of the cost of a reservoir simulation computer run. On other problems, however, the solution method can problems, however, the solution method can become sufficiently slow so that the matrix problem dominates the computer cost. problem dominates the computer cost.
A New Approach to Parameter Estimation in Well Testing
Authors: Padmanabhan L. , Woo P.T. 
Published: December 2007

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

Introduction
Although computer solution technique are used universally in reservoir simulation and history matching problems, in the context of well testing one finds an almost exclusive reliance on the conventional graphical techniques (build-up and drawdown plots and type curves). While these graphical methods have been remarkably successful in providing quick answers and valuable providing quick answers and valuable insight into the reservoir structure, they are somewhat limited in scope and impose some strong restrictions on the test schedule. The practical difficulties in applying these methods are that the assumptions on which they are based do not often hold, the flow rates are variable or even unknown during certain phases of the test and finally the estimates of the parameters obtained from different methods may vary widely. It is true that the Horner-buildup and drawndown analyses can be extended to accommodate variable flow rates by a judicious application of the superposition principle to asymptotic analytical solutions [Ridley]; however, the information that can be derived pertaining to the damage near the wellbore is far from complete or accurate. Indeed all that can be inferred about well-damage is in terms of a skin factor and not whether this "skin" is really due to a plugging of the perforations or due to plugging of the perforations or due to mud invasion into the formation and how far into the formation that the damage persists. None of these methods operate satisfactorly if flow data are missing; moreover the assumption of a constant flow rate in place of missing information on flow rate may in fact lead to misleading results. If one has to use type curves, the results are often ambiguous as they are based on very subjective judgements on what is or is not a matching overlay between data and the type curve. In spite of the existence of myriads of such methods, when it comes to the simultaneous estimation of several reservoir parameters, both local and far from parameters, both local and far from the well, there is no unifying procedure that produces a unique answer. This stems partially from the fact that most of these methods are based on the long-time asymptotic solutions of the radial flow equation.
Experimental and Calculated Relative Permeability Data for Systems Containing Tension Additives
Authors: Talash A.W. 
Published: December 2007

Experimental and Calculated Relative Permeability Data for Systems Containing Permeability Data for Systems Containing Tension Additives
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Improved Oil Recovery Symposium of the Society of Petroleum Engineers of AIME, to be held in Tulsa, Okla., March 22–24, 1976. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
In order to predict recoveries for low tension waterfloods, one must have information on the relative permeabilities of oil and water under conditions approaching miscibility. In this study relative permeability data were obtained by two conventional methods, the displacement method and the steady-state method, in fired Berea cores for a crude oil-water system containing tension reducing additives (surfactants). Four surfactants were utilized, two being preferentially water-soluble and the other two being preferentially oil-soluble but not to the same degree. From the measured data, equations were developed for calculating relative permeability data for the systems examined. As a test, the equations developed were utilized in a one-dimensional reservoir simulator program for computing laboratory waterflood performance. The comparison given in the paper shows that the calculated values were in good agreement with the measured results.

Introduction
In order to mathematically simulate laboratory waterfloods one must have accurate relative permeability data. These data are usually obtained in one of several ways, namely,Direct MethodsSteady-StateDisplacementStationary-PhaseNuclear Magnetic ResonanceIndirect Methods (by calculation, using proven equations)Naar-Wygal EquationsLand Equations
The direct methods, as listed above, are much preferred over the indirect methods; however, a complete set of relative permeability data is rarely found.
An Experimental Study of Acid Placement in Variable Inclination Laterals
Authors: Zhu D. , Hansen A. , Bruksas R. , Hill A. D. 
Published: December 2007

Abstract
Acidizing a horizontal well is more complicated and difficult than acidizing a vertical well. The fluid distribution in a horizontal well is affected by a longer wellbore length, a broader variation in the reservoir properties along the wellbore, and possibly different mechanical means to place the fluids in the wellbore. Since a nominally horizontal is not perfectly horizontal, the wellbore trajectory may have numerous upward and downward inclined sections. This allows the injected fluid to under-ride or over-ride the resident fluid. Gravity effects could result in acids (often a denser fluid than the resident fluids in the wellbore) preferentially treating the low spot in such a well.
We have conducted several experiments to study the effect of gravity on acid placement in horizontal wells. The experimental apparatus contains two pipe segments with adjustable inclination to simulate a high spot (crest) or a low spot (trough) in a nominally horizontal well. The experimental results were used to characterize fluid placement in horizontal well acidizing, and to verify a mathematical model developed previously1,2.
We observed from the experiments that in both trough and crest cases, gravity under-riding influences the acid placement along the wellbore significantly. The comparison of the experimental results with the simulation result from the mathematical model developed before shows good agreement, and therefore validates the mathematical model.
Carbonate Matrix Acidizing with Acetic Acid
Authors: Huang T. , Ostensen L. , Hill A. D. 
Published: December 2007

Abstract
Conventional matrix acidizing in carbonate reservoirs uses hydrochloric acid to remove formation damage and stimulate well performance. Many experimental and theoretical studies in carbonate acidizing have confirmed the existence of an optimal acid injection rate at which major wormholes are formed, and the benefit from stimulation is maximized. This optimal rate depends on reservoir conditions, rock properties and chemical reaction rate. At high reservoir temperature, the optimal rate of hydrochloric acid is usually too high, and it sometimes is beyond the maximum injection allowed (the rate to avoid fracturing formation). In this case, weak acids, such as acetic acid, are alternative fluids to stimulate the wells. In our previous study, a theoretical model showed that under the same condition, the optimal injection rate for weak acids is relatively lower than the one for strong acids.
This paper presents an experimental study of the wormholing process in carbonate acidizing with acetic acid. Carbonate rock samples were acidized, and the effectiveness of the process and the optimal injection rate were studied by measuring the acid volume needed to propagate wormholes through the cores and by making castings of the wormhole structures after acidizing. The experimental results from this study confirmed that the optimal injection rate of acetic acid is lower than the optimal rate for hydrochloric acid. It also showed from the castings that the radius of wormholes created by acetic acid at the optimal rate is larger than that created by hydrochloric acid at the optimal rate. We then demonstrate how these results can be used to determine the optimal acid system and injection schedule for field application.
The Nature of the Compacted Zone Around Perforation Tunnels
Authors: Arora Devinder S. , Sharma Mukul M. 
Published: December 2007

Abstract
The creation of perforation tunnels through the use of shaped charges is often found to leave a zone of compacted rock of low permeability around the tunnel. The low permeability of this compacted zone is a result of grain crushing and fines accumulation. Laboratory experiments reported earlier indicate that the distribution of fines and the permeability around the perforation depend on several factors including underbalance pressure, rock strength and fluid properties.
In the present work, a model has been developed to understand the factors controlling the permeability distribution around a perforation tunnel. During underbalance perforating, the permeability of the region around the perforation is controlled by fines generated by the shock wave and by fines entrained during surge flowback into the wellbore. Surge flow around the perforation tunnel determines the radius of the tunnel formed as well as the cleanup of fine-grained material near the face of the perforation. Fines are mobilized around the perforation tunnel wherever the surge velocities exceed a critical velocity. Some of the mobilized fines are trapped at pore throats near the tunnel giving rise to the crushed zone while those very close to the tunnel (~0.5 cm) are produced. The crushed zone thickness is found to increase with rock tensile strength, fines content and fluid viscosity. The model also clearly shows why a lower optimum underbalance pressure is required for higher permeability rock. Results from the model are compared with experimental data on fines content and permeability around a single perforation. Good agreement is obtained with lab and field observations as the key parameters (rock permeability and underbalance pressure) are varied for both gas and oil wells.
OCCAM: Onset-Constrained Colloidal Asphaltene Model
Authors: Correra Sebastiano , Donaggio Francesca 
Published: December 2007

Abstract
Asphaltene deposits affect the primary production of oil from the wellbore to the surface facilities and may also cause problems during storage and pipeline transportation. A model to predict the occurrence of asphaltene separation is therefore required in order to avoid or minimize upsets due to asphaltene precipitation.
With the aim of identifying the physical nature of the asphaltene separation, both onset-of-precipitation and quantity-of-asphaltene experimental data were produced. While in general previous researchers have tried to apply or adapt well-known models to describe the experimental results, the peculiar behavior observed for asphaltenes has been used here to gain insight into the mechanism of precipitation. From this work a model (Onset-Constrained Colloidal Asphaltene Model) has been developed, allowing predictions of asphaltene flocculation from standard PVT data and a limited set of experimental data on stabilized oil. Because it is physically well founded, the model is applicable to any situation in which asphaltene separation is possible; it allows prediction of both the precipitation onset and the quantity of asphaltene that separates as a function of oil composition, temperature and pressure.
Model applications show good agreement between predicted and experimental data on stock tank oils; moreover upstream applications are shown which further confirm model results. Besides, the model explains numerous experimental observations and physical descriptions of many other researchers, so that it is further reinforced by the prior literature.
A new insight into the phenomenon of asphaltene precipitation was gained and an original model was built, so that most of previous experimental data can be included in this framework.
How Effective is Underbalanced Drilling at Preventing Formation Damage?
Authors: Santos Helio , Queiroz J. 
Published: December 2007

Abstract
A series of return permeability tests with foam has been conducted to evaluate the potential formation damage while drilling underbalanced (UBD). The tests were conducted with overbalanced pressure, simulating the conditions when killing the well is necessary to perform some operations while drilling. The results indicated significant permeability reduction, even when just water was used as drilling fluid. A deep study was then conducted to investigate the potential causes of the damages and to define the best way to remedy this problem.
The results obtained from the laboratory investigation show a need for the industry to better plan UBD operations to avoid undesired permeability reductions. Discussion of some damage mechanisms accepted today is presented, as well as some suggestions to extract the most out of a UBD job. According to the results it is essential to develop ways to have an underbalanced condition at all times while drilling. Even completion should be planned to be conducted without exposing the formation to overbalanced pressure. It is extremely important to pay attention to the periods during which the formation is exposed to an overbalanced condition, and try to avoid them as much as possible.