bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Semi-Analytic p/z Rate-Time Relation for the Analysis and Prediction of Gas Well Performance
Authors: Ansah J. , Knowles R. S. , Blasingame T. A. 
Published: December 2007

Abstract
This paper presents a rigorous theoretical development of long term boundary-dominated flow solutions which involve direct coupling of the stabilized flow equation with the gas material balance equation. Due to the highly non-linear nature of the gas flow equation, pseudopressure and pseudotime functions have been used over the years for the analysis of production rate and cumulative production data. While the pseudopressure and pseudotime functions provide a rigorous linearization of the gas flow equation, these transformations do not provide direct solutions. In addition, the pseudotime function requires the average reservoir pressure history—which in most cases is simply not available.
Our approach uses functional models to relate the viscosity-compressibility product with the reservoir pressure (p/z) profile. These models provide approximate, but direct, solutions for modelling gas flow during the boundary-dominated flow period. For convenience, the solutions are presented in terms of dimensionless variables and expressed as type curve plots. Other products of this work are explicit relations for p/z and Gp(t). These solutions can be easily adapted for field applications such as rate prediction.
We also provide verification of our new flowrate and pressure solutions using numerical simulation results and we demonstrate the application of these solutions using a field example.
Potential Distribution Around Sources With Finite Length Horizontal and Vertical Partially Penetrating wells and Fractures Part I: Steady State Fluid Flow
Authors: Azar-Nejad F. , Tortike W. S. , Farouq Ali S. M. 
Published: December 2007

Abstract
The mechanism of fluid flow in the reservoir can be determined through the knowledge of the potential distribution inside the reservoir. Presenting Discrete Flux Element (DFE) Method this paper provides a general analytical solution to potential distribution due to a producer with straight or curvilinear configuration for both uniform flux and uniform potential inner boundary conditions in 3-D. The results consist of: 1) the equations for productivity indices, 2) shape of the drainage area for each case. This study shows that the drainage area for a horizontal well, beyond a certain radius is vertical in the vertical planes (xz and yz). In the horizontal planes it is first elliptical and at points far from the producer it is circular.
Applications of Azimuthal Anisotropy from Dipole Shear Sonic in Western Venezuela
Authors: Johnston L. K. , Campo O. , Lagoven S. A. , Viloria O. 
Published: December 2007

Abstract
Wellbore mechanical properties have long been used to model formation responses when planning highly deviated wells, horizontal wells and fracture treatments. Now, with the inclusion of the maximum stress direction and horizontal stress ratio, a complete model of the formation response to stress can be obtained.
The fact that shear waves will split and become polarized parallel and perpendicular to natural fractures is well documented. The fact that the fast shear wave is oriented in the direction of the maximum horizontal stress is also well documented. Cross dipole shear data from a digital sonic tool is processed to obtain oriented fast and slow shear waves. The theory of shear anisotropy processing is reviewed and the quality control and interpretation of the resulting anisotropy log are discussed.
For this case study, azimuthal anisotropy data obtained from dipole shear sonic logging in Western Venezuela is used to determine the direction of maximum horizontal stress and horizontal stress ratio. This information is then used to determine the oriented mechanical properties. These mechanical properties are presented in the form of an oriented wellbore stability analysis.
When the information obtained from dipole shear sonic anisotropy logging is used in the planning of horizontal wells, deviated wells and fracture treatments the overall cost of the well can be reduced. Using this information, efficiency can be increased and potential problems can be avoided.
The Contribution of Wellbore Imaging to Interval Selection in Naturally Fractured Reservoirs
Authors: Mendoza R. J. 
Published: December 2007

Abstract
The selection of intervals to be perforated in naturally fractured reservoirs is often aided by the use of wellbore images.
The current trend in several mexican fractured reservoirs is to include an analysis of wellbore images to define production intervals.
Visualization of the rock texture is also possible from images, and differentiation of secondary porosity types can be defined. Standard logging techniques to detect fractures do not distinguish betwen unconnected vugs and open natural fractures. In tight carbonate formations, hydrocarbon production comes mainly from these fractures.
Other data that can be obtained from the images are the orientation and frequency of fractures, their relationship with the reservoir structure and porosity, and their distribution.
This paper includes examples and correlations betwen producing intervals and wellbore images.
A New Practical Approach to Rotary Drilling Hydraulics
Authors: Scott Kenneth F. 
Published: December 2007

Abstract
This paper presents a simple, practical and accurate method of selecting jet bit nozzle sizes. Rather than calculating friction losses in the drilling system, a measure of total friction loss is taken from the standpipe and a graphical solution of pressure loss across the bit is subtracted from the standpipe reading, resulting in the actual measurement of system pressure losses. Drilling hydraulics are based pressure losses. Drilling hydraulics are based on maximum bit horsepower, hydraulic impact, or jet velocity and are all dependent on a predetermined friction loss in the system. predetermined friction loss in the system. This method may be used to maximize any one of the three.
Because mud properties and hole conditions change, nozzle size selection is made from data obtained prior to pulling a dull bit out of the hole. A work graph is presented, and typical field data are used in working example problems.

Introduction
The subject of rotary drilling hydraulics has received a great deal of attention in the literature. Excellent papers have been written by Bobo, Kendall and Goins, and Kelly. Recent trends have been to maximize bit hydraulic impact. Examples will be worked in this paper which will maximize hydraulic impact and bit horsepower.
The derivation of the maximum horsepower, impact force, and jet velocity equations are presented in an excellent paper by Kendall and presented in an excellent paper by Kendall and Goins.
Conditions that are necessary for maximizing any of these three parameters are listed without derivations in Table 1.
Graphs are presented for obtaining circulation rates for various pump liners, stroke length, and strokes Graphs 1A and 1B).
A nomograph of annular velocities-vs-circulation rates for various hole and drillpipe size combinations is presented (Graph 2).
The method for constructing the work graph from which nozzle sizes are selected is presented. Field examples are solved in the discussion.
Financial Planning in a National Oil Company: The Mexican Case
Authors: Rivera V. Miguel A. 
Published: December 2007

Abstract
Although financial planning is a business tool widely used by the international business community, its use by Petróleos Mexicanos (PEMEX) hardly began at the end of the previous decade. For almost fifty years the Mexican Oil Company dealt with volumetric targets and within an administration scheme very similar to any federal agency, instead of an international oil company, as it really is. A deep process of structural change started in 1990, aimed to maximize the assets economic value. Within this context, it became necessary to structure a financial planning scheme to monitor the huges investments of the industry, which projects are undertaken in a long term framework and the capital resources applied for those projects have a very important leverage in the Mexican economy. Despite several limitations that the Mexican Government still applies on PEMEX, mainly regarding budgeting and taxation, the Company has been developing a "sui generis" financial model to enable the top management to design mid and long term financial plans, taking into account the predefined strategies, objectives and targets. Considering that PEMEX is placed among the ten most important worldwide oil industries and also the greater flexibility on federal regulations, the Company is obliged to increase its financial planning efficiency in order to achieve the same operation level of other international oil industries.
Production Control Systems Deep Water Installation and Maintenance Features
Authors: Doyle Hickok P. E. 
Published: December 2007

Abstract
The movement of subsea production systems into water depths beyond practical diver working range presents challenges in the ability to install and maintain the equipment. The partitioning of systems into manageable pieces is critical to their successful remote installation and maintenance. Consideration of equipment size and weight with respect to support equipment constraints and ROV capabilities has resulted in a set of equipment that is flexible in its application to deep water requirements. A complete set of support tooling for installation of umbilicals, control pods, electrical and hydraulic distribution modules and their associated interconnections in deep water has been proven.
Second-Contact Water Displacement Oil Recovery Process
Authors: Lepski B. , Bassiouni Z. , Wolcott J. 
Published: December 2007

Abstract
The Double Displacement oil recovery process (DDP) consists of injecting gas into waterflooded oil zones. Upon contact with the injected gas, residual oil globules spread out and form a thin film. Subsequent drainage of the oil film creates a bank which migrates downdip and can be produced. The technical feasibility of DDP has been tested in three fields and is currently being investigated by a joint DOE/Amoco project.1 During laboratory investigation of the DDP at LSU, we observed that a significant amount of oil was displaced when gas-flooded zones were subjected anew to water displacement2. This process was termed Second-Contact Water Displacement (SCWD).
Consolidated cores and unconsolidated sandpacks were flooded at high-pressure and high temperature to simulate different aspects of the process. In addition, experiments using low-pressure transparent cells were performed to gain conceptual insight into the process. Core and sandpack experiments proved that second-contact waterflooding following gas injection could recover up to 20% of oil remaining after the initial water contact.
This process can be used in conjunction with the Double Displacement Process to shorten its duration hence improving its economic potential. The process can also be applied in single-well strong water-drive reservoirs in conjunction with attic-oil recovery.
Development of an Improved Waterflood Optimization Program in the Northeast Savonburg Waterflood
Authors: Schoeling L. G. , Barnett G. B. , Michnick M. J. , Walton A. W. , Green D. W. , Willhite G. P. 
Published: December 2007

Abstract
The Savonburg Field, a shallow reservoir located in southeastern Kansas, has production problems which are common in fluvial dominated deltaic reservoirs and other areas of the country where stripper-well production is important. The problems relate to poor waterflood sweep and lack of an integrated reservoir management program. The poor water-flood sweep efficiency is due to (1) reservoir heterogeneity, (2) channeling of injected water through high permeability zones or fractures, and (3) clogging of water injection wells with solids as a result of poor water quality. Reservoir management suffers from the lack of (1) sufficient data collection and organization, (2) integrated analysis of existing data by geological and engineering personnel, and (3) identification of optimum recovery techniques.
A project to increase oil recovery from the Savonburg Field is being conducted under the DOE Class 1 Program. The objective is to improve waterflooding through integrated reservoir management. To date, two technologies have demonstrated positive economics. An air flotation unit has demonstrated that the poor water quality can be improved economically with reduced costs compared to previous operations. Permeability modification treatments plugged channels and increased oil recovery. Earlier treatments yielded five barrels of incremental oil per pound of polymer injected and recent treatments have improved injection profiles. Reservoir characterization studies identified unswept oil in the lower B3 zone and as a result two waterflooding patterns were modified and a new injection well was drilled. Incremental oil is expected to result from this change.
Long Term Use of Oxidizing Agents in Utah Salt Water Disposal Results in Increased Injection Rates and Reduced Operating Costs
Authors: Romaine J. , Vickers Bill , Smith P. 
Published: December 2007

Abstract
The harmful effects of bacteria and sulfidic sludge on the performance of waterflood injection and disposal systems are well known 1–5. Solving this problem by acidizing lines and wells, and manual removal of biomass and sulfidic pads from tanks, is costly in terms of both dollars and time. Treatment with the production chemical chlorine dioxide was seen as a less costly option. Union Pacific Resources Company's, (UPRC), Pine view operation in Utah was the site for the application described. Chlorine dioxide has treated 12,000–13,000 barrels of water per day since 1991 removing and controlling iron sulfide and bacteria in the water injection disposal system. As a result this program has shown documented savings to UPRC of $1.72MM over the last four years.
Effect of the Core Material on Gelation of a HPAM / Chromium System at High Temperature
Authors: Kolnes Jostein , Nilsson Svante 
Published: December 2007

Abstract
The system studied is designed for deep injector treatment, and can also be applied for treatment of a hot producer. Hence, it consists of polymer at a rather low concentration (0.5 weight% polyacrylamide) to ensure high mobility of the gelant. The crosslinker is chromium (oxidation state 3) protected by malonic acid, in order to slow down the gelation process, and to reduce retention.
Large differences in the gelation process are observed depending on whether the gelation occurs in bulk or in a core. Also, large differences are observed between different cores. Here two outcrop sandstones (Berea and Bentheimer), and a North Sea reservoir sandstone have been used. The gelation process shows variations in: gelation time, critical chromium concentration, and changes in pH during gelation. Three important properties of the core material causing this behavior have been identified: 1) content of carbonates (mainly CaMg(CO3)2 and CaCO3) which controls the pH, and thereby the gelation time, the stability of the gel, and precipitation of chromium; 2) content of iron (mainly as FeCO3) - which affects the stability of the polymer; and 3) the amount of clays, which governs the cationic exchange capacity, and thereby the retention.
The gelant behavior in the core material has to a large extent been reproduced in bulk by adding appropriate amounts of kaolinite, and the minerals/chemicals mentioned above, to the bulk solution. It is also shown how to compensate for these changes induced by the core material.
The results from our study show that it is extremely important to know the mineral composition of the reservoir rock before a gel treatment is applied. This knowledge will enable us to avoid breakdown of our gel in regions where we want it to block water, and the prediction of shut-in time in case of a producer treatment is improved. In addition, our findings suggest that for reservoirs where there is a good correlation between low permeability and high clay content of the sand, which often is the case, one might avoid zone isolation when placing the gelant. Even for a relatively high value of vertical to horizontal permeability, a successful gel treatment seems possible with bullhead injection. The treatment can be used both for injectors and producers, and the effect will increase with increasing depth.
Necessity of Dual Injection for Gelant Placement in the High Permeability Layer of a Reservoir with Crossflow
Authors: Shah P. C. , Gao H. W. 
Published: December 2007

Summary
During the water-flood in a layered reservoir, the high permeability layers will be swept first, leading to a large production of water through such layers. The oil in the adjacent lower permeability layers may be left unmoved unless water shutoff treatment is administered to the thief layers. This work considers a prototype two layer reservoir with crossflow of this nature and investigates the problem of placing a gel plug in the high permeability layer in the vicinity of a producer well for water control treatment. Due to the crossflow, the gelant injected into the high permeability layer may invade the oil zone and shut-off oil production from a part of that layer as well. The depth of the unwanted vertical travel of the gelant into the oil zone is studied through simulation for a variety of reservoir and gelant parameters. The gelant invasion of the oil zone may be reduced or completely eliminated through use of the dual injection method of placement. The situations where dual injection is necessary are identified in this study.
If there is a significant flow channel near the wellbore that allows crossflow between the two layers, the dual injection method is absolutely required for acceptable gelant placement. Gravel pack completed wells also present a very similar problem due to crossflow through the gravel pack. In presence of such a crossflow channel the pressures of the two fluids in dual injection have to be matched very closely to successfully place the gelant in the thief layer.
Acrylamide-copolymer Gel for Profile Modifications: A Case Study in Central Sumatra Basin, Indonesia
Authors: Gandawidjaja Purbaya , Indra H. P. 
Published: December 2007

Abstract
Reservoir heterogeneity is a cause of poor oil recovery in a majority of reservoirs. It provides a path for uneven fluid flow from pressure source to pressure sink. The pressure source can be an injection well or bottom water drive. This paper presents applications of Conformance Technology using Acrylamide copolymer Gel treatments to enhance recovery efficiency. The matrix conformance problems in Sago field, Central Sumatra Basin of Indonesia, have caused water production problems leading to early abandonment and loss of recoverable reserves.
The application of this water shut-off program is expected to automatically shut-off the watered-out high permeability streaks, which in turn will utilize the reservoir pressure increase to be redirected into the lesser permeability streaks still containing bypassed oil, so that better sweep efficiency will be achieved. Adding to the reservoir results of improving both pressure and sweep efficiency, significant decrease of water cut will lower the water production rate, resulting in the decrease of the unit production cost of US$/bbl. The expected increase of oil production rate will give a still better economic value of the project.
Substantial decreases in water production have been realized and in some cases, also increases of the oil production rates as the results of profile modifications achieved through proper treatment applications, strict screening criteria, and extensive laboratory as well as field tests conducted prior to treatments.
Effects of Pressure on Foam Stability; Implications for Foam Screening
Authors: Holt T. , Vassenden F. , Svorstøl I. 
Published: December 2007

Abstract
The stability of foam in porous media has been investigated by core flooding at pressures from 10 to 300 bar, both in the presence and absence of oil. A C16 alpha olefin sulphonate (AOS) and a fluorinated betaine surfactant was studied. In the absence of oil, both surfactants displayed increasing apparent viscosity with increasing pressure. The functional form of the pressure dependence differed for the two surfactants, however. The apparent viscosity increased by a factor of 30 for C16 AOS, and a factor of 3 for the fluorinated surfactant. At 300 bar, the two surfactants performed identically. In the presence of oil (hexane-diluted stock tank oil at low pressure and reservoir oil at high pressure), C16 AOS again displayed increasing foam stability with increasing pressure, while the fluorinated betaine showed the opposite trend.
The data from experiments in oil free cores are discussed in terms of the limiting capillary pressure theory, and measured pressure variation of the surfactant solution surface tension.
The effects of oil on foam stability was assessed by measurement of spreading and entering coefficients at different pressures. For C16 AOS, no change in these coefficients was observed between 20 and 300 bar. For the fluorinated surfactant both coefficients changed significantly, to values indicating detrimental oil-foam interaction at high pressure. Thus, the change in oil-foam interaction seem to explain that the fluorinated surfactant did not show increasing foam stability with pressure in the presence of oil.
The observations show that both the foam stability in absence of oil and the oil-foam interactions varies differently with pressure for different surfactants. This implies that flooding experiments at reservoir pressure are required for a proper screening of foamers.
How To Operate Offshore Production By Remote Control
Authors: Miller Sam K. , Bradham Allen C. 
Published: December 2007

Gulf Oil Corporation has installed a unique supervisory control and data telemetering System for three high-pressure gas-condensate wells located in Block 889 near Mustang island, Texas, in the Gulf of Mexico. Automatic instrumentation provides for control functions; measurement of production variables; alarms and monitoring; and platform security.

Production Platform - Block 889, Mustang island Field
This system control point is located on the bay side of Mustang island at the onshore separation and storage facilities. All control functions, signals and process data are transmitted over a single pair of wires through a submarine electric cable between the offshore platform and the onshore control station.
The automatic system has resulted in a net savings of $4,852 per month as compared to manned operations.