bluuebunny/crossref_metadata_2025 huggingface dataset:
Casing Point Selection at Shallow Depth
Authors: Aadnoy B. S. , Soteland T. , Elligsen B.
Published: December 2007

Different oil companies place shallow casing strings at different depths. Apparently there is no general method or procedure that gives the optimum location. This paper is an attempt to define this optimum casing seat location. Potential benefits are improved safety and economy of the operation.

Two main factors determine the depth of the casing shoe, namely the fracture pressure and the pore pressure. A third factor is lithology, since it is desirable to place the casing shoe in a competent shale section. Methods to predict fracture gradients for deeper wells already exist. In this paper a method to predict fracture gradients for shallow wells is derived. This method is combined with kick tolerance criteria to yield a casing depth selection method. Also, the variation in fracture pressures at any depth is investigated.

A case study of a field offshore Norway is performed. The preliminary conclusions are that the 30 in. casing setting depth is difficult to model, while the 20 in. casing string could be set at shallower depths. The large spread in leak-off pressures of the field is further investigated. Some of the spread is found to be caused by the failure mechanisms of the rock, and is therefore unpredictable. However, part of the spread in observed fracture gradients seems to correlate with mud properties. Improved hole strength is therefore possible by building a proper mud.
Simulation of a Naturally Fractured Reservoir, Point Arguello Field, Offshore California
Authors: Van Bloemen Waanders B. G. , Litvak B. L.
Published: December 2007

A computer simulation methodology is presented to help direct development of the Point Arguello Field, California Offshore, Santa Maria Area. The Monterey producing formation is naturally fractured and exhibits extreme lithological variation both vertically and horizontally. The fluid-flow characteristics are extremely complex and present many challenges to reservoir management. As part of a continuously evolving process, the initial phase of this simulation project consists of calibrating a double-porosity model with quality data interpretation results and to do so without benefit of production history. Pressure-transient test results dominate the major portion of the model calibration process, although results from logging, coring, and fluid analyses were also used. Various reservoir-parameter sensitivities were studied to determine the effects of the dominating characteristics on production forecasting. The objectives of the sensitivity studies consisted of the determination of optimum development strategies such as evaluating the need for infill drilling and selecting correct perforating intervals. Production forecasts were generated to compare different development scenarios, and, based on these forecasts, development directions were provided for the Point Arguello Field.
An Interporosity Flow Model for Naturally Fractured Reservoirs
Authors: Jalali Y. , Belani A. , Fujiwara K.
Published: December 2007

The producing capacity of a naturally fractured reservoir is governed by interporosity flow since most of the fluid resides in the rock matrix. A distributed formulation is introduced to account for variability in the strength of interporosity flow across the reservoir. The model can account for deterioration or enhancement of reservoir producibility resulting from development of interporosity skin and closure of fractures or hydraulic fracturing and acidizing. This formulation suggests a reason why certain naturally fractured reservoirs do not experience sudden rate decline as predicted by classical double porosity models.
Evaluation of Oily Waste Injection Below the Permafrost in Prudhoe Bay Field
Authors: Abou-Sayed A. S. , Andrews D. E. , Buhidma I. M.
Published: December 2007

This paper presents the results of an extensive study and field test carried out at the site of Prudhoe Bay's four oily waste injection wells. The field work was part of an overall environmental assessment intended to: (1) confirm earlier results indicating that no fluid communication was occurring with the permafrost; (2) determine optimum conditions for the disposal of waste in the presence of hydraulically-induced fractures; (3) substantiate that an increased injection pressure could be safely implemented. A three day injection test, including a step-rate stage, was carried out. Data collected included surface and downhole pressures, in-si tu stress measurements, and monitoring of ground surface deflections and wellbore hydraulic impedance.

Radially symmetric surface tilt patterns showed that the test well connects to a horizontal fracture of 60-foot radius. Wellbore impedance indicated that a horizontal fracture with 9-18 foot radius communicated with the well. Integration of rock mechanics, historical information, and the collected data provided a clear picture of what was occurring underground. The different evaluation techniques showed consistent results as reflected in the estimated fracture size, placement and damage zone properties.
Evaluation of a Complex Sandstone Reservoir for EOR
Authors: Pathak P. , Kuch K. D. , Kriel B. G. , Pasternack E. S. , Moorefield T. P. , Ligon J. H. , Salter S. J.
Published: December 2007

A methodology for evaluating a complex reservoir for an EOR process is presented in this paper. In this methodology, two factors are emphasized. First, utilization of a stagewise workplan with numerous go / no-go decision points is shown to be important in avoiding the expenditure of significant time and money in the application of an EOR process to an inappropriate reservoir. Second, the importance of a multi-disciplinary workteam is emphasized. The tasks required to carry out such a reservoir evaluation involve diverse knowledge and skills beyond the ability of any one discipline. Finally, the workplan must be tailored to the specific needs, or characteristics, of the reservoir.

In this paper, we evaluate the South Cuyama Field for the application of Micellar-Polymer Flooding. The South Cuyama reservoir is a mature field in California that has both complex geology and a complex operational history. Two factors were found to be critical in determining the viability of the micellar process in South Cuyama. First, the faulted nature of the South Cuyama sands emphasized the importance of sand continuity between injectors and producers. Second, in order to make the EOR process profitable, the remaining oil in South Cuyama had to be large enough to justify the added expense of process implementation.

This paper presents the results of a multi-disciplinary study by engineers, geologists and geophysicists from the Research, Engineering, and Operations organizations. This study starts with preliminary reservoir screening based on average reservoir properties, progresses through the reanalysis of existing data to acquire an updated picture of the reservoir and determine the key questions to be answered, describes a joint geological / geophysical study which included a 3D, high-resolution seismic study, reports the results of field work done in existing wells, presents the results of updated material balance and volumetric studies, and describes the drilling and coring of a reservoir delineation well along with the analysis of the core. Particular emphasis is placed on determining the amount and distribution of remaining oil saturation, which is studied by log-inject-iog tests, single-well tracer tests, laboratory core analysis, reservoir performance, and OOIP studies. The progression of the workplan is in the order of increasing effort and expense. As key questions are identified and critical data found lacking, we progressed logically to the next step. The results of this study show that South Cuyama is not a good candidate for micellar-polymer flooding. Using the methodology presented here, we were able to determine this fact without actually running a pilot test, thereby saving considerable expense.
Use of Downhole Pulsation Dampener To Eliminate the Effect of Fluid Inertia on a Rod Pump System
Authors: Svinos J. G.
Published: December 2007

Fluid inertia effects increase equipment loading and reduce efficiency in high rate shallow wells with very low gas production (producing more than 800 BPD from depths of less than 2,500 feet). In deeper wells this effect is negligible. However, in shallow, high rate rod pump wells that are primarily found in California, fluid inertia is one of the dominant factors affecting system loading and performance. This effect is one of the main reasons most design methods for rod pump systems do not agree with field measurements for shallow wells.

In an attempt to reduce the damaging effects of fluid inertia, a prototype of a downhole pulsation dampener was successfully field tested in a California well with severe fluid inertia effects. As Figure 1 shows, the device consists of a perforated pup joint of tubing covered by a Kevlar reinforced elastomeric bladder. This assembly is enclosed in a sealed steel outer housing. The volume between the bladder and the housing is pre-charged with nitrogen to a pressure equal to the tubing pressure at the point of installation. For the test, the dampener was installed as the first joint of tubing above the pump.

The device operates as follows: On the upstroke, as the traveling valve closes, the plunger picks up the fluid load and accelerates it creating a pressure pulse. The dampener absorbs this pulse as bladder expansion compresses the nitrogen. On the downstroke, as the pressure in the tubing drops, the bladder returns to its original position.

The downhole pulsation dampener completely removed the fluid inertia effects. Dynamometer cards showed a dramatic difference in shape between the "before" and "after" cases. Dynamometer analyses for before and after dampener installation show the device was effective in reducing gearbox loading by 36 percent, sucker rod loading by 22 percent and polished rod horsepower by 20 percent. Fluid level and production rate remained approximately the same.
Simulation of the Bishop Steam Foam Pilot
Authors: Patzek T. W. , Myhill N. A.
Published: December 2007

In this paper we present a simple model of steam foam transport and apply it to the Shell Kern River Bishop pilot. The only adjustable parameter in the model is an effective surfactant partition coefficient that accounts for surfactant losses and inefficiencies of foam generation, and determines foam propagation rate. Once this partition coefficient is calibrated to match observed foam growth in the pilots, the simulator correctly predicts an incremental 5.5 percent OOIP recovery due to steam foam and additional 3 percent OOIP due to infill wells.

"What-if" simulations using an "enhanced" steam foam (twice as strong as AOS-1618, propagates 20 percent faster and reduces ROS by 7 percent) show a dramatic increase in incremental oil recovery (17 versus 5.5 percent OOIP in the Bishop pilot) and a dramatic reduction in surfactant requirement (5 versus 15 lbs AOS/Bbl incremental oil).
Comparison of HASDrive and Sand-Filled Multiple Communications Steam Recovery Processes for Heavy and Extra-Heavy Oil Reservoirs
Authors: Toma P. , Reitman V. , Coates R. M. , Heidrick T. , Ridley R. K.
Published: December 2007

An assessment of two novel, steamdrive recovery processes for heavy oil reservoirs is presented.

Special experimental procedures were designed and used to assess and compare steamdrive recovery processes using a HAS-pipe or a sand-filled channel (SFMC) in a simulated tar sand field. It was found that temperature development and distribution of saturation progress more uniformly around the HAS-pipe than around the sand-filled channel, and this could explain higher initial recovery rates observed for SFMC than for the HASDrive process. A multicomponent thermal numerical model was first validated against laboratory experiments and was then used to assess the influence of reservoir properties such as formation depth and oil viscosity, on recovery processes employing either (SFMC) or HASDrive-hot pipe strategies.

The effectiveness of each process was assessed using the final recovery and diagrams of the key characteristics of oil-steam ratio versus running time.

The results indicate that for shallow heavy oil reservoirs the HASDrive process can be more effective than the SFMC process. The situation is reversed for higher permeabilities and deeper formations, where a better chance of effectively recovering the viscous oil is indicated for the SFMC process.

A new steamdrive recovery process employing a HAS-pipe embedded in a sand channel is suggested for shallow heavy oil formations. This process was analyzed and compared to both the SFMC and HASDrive recovery processes.
Wellbore Drillstring Mechanical and Hydraulic Interaction
Authors: Saleh S. T. , Mitchell B. J.
Published: December 2007

Hole enlargement is a common problem encountered in drilling practices. It is the purpose of this paper to address the effect of hydraulic and mechanical forces acting on the wall of the wellbore. Field data from the Williston Basin (caliper logs, bit records, mud recap sheets) were used in correlating the effect of various hydraulic and/or mechanical parameters versus hole enlargement. In addition, the paper describes analytical techniques for the determination of hydraulic and/or mechanical forces created by the drill string and/or the movement of the drilling fluid.

The investigated hydraulic parameters are the annular flow regime, annular pressure losses, mud rheology, jet impact force, surge pressure, and the hydraulic effect of rotating and orbiting drill string. The power law model was used to calculate annular pressure losses and Reynold's number. Hydraulic forces created by the rotation of the drill string were computed with classical rotational viscometer model.

Mechanical forces of the drill string acting on the borehole wall were investigated below and above the neutral point of bending. Two types of holes were studied: straight and vertical holes, and vertical and doglegged holes.

Analysis with the author's model shows that the inertial force causes the drill pipe to contact the wellbore between the tool joints, and the corresponding contact forces was determined as a function well depth.
Multiphase Well Test Analysis: Pressure and Pressure-Squared Methods
Authors: Al-Khalifa A. J. , Horne R. N. , Aziz K.
Published: December 2007

There are two practical approaches to analyze multiphase well tests. These are the pressure and the pressure squared methods. This paper investigates the limits of these methods as they apply to different reservoir and testing conditions.

The pressure squared approach is applicable to systems in which a gas phase is present (i.e. gas-oil and gas-oil-water systems), while the pressure approach is superior for application in oil-water systems.

Unlike the pressure squared approach, the pressure approach is found to be rate sensitive and only applies at low flowing rates. The higher the flow rate, the greater the underestimation of the individual and total system mobilities. For some cases, the pressure semilog plot does not exhibit any straight line; while for other cases it shows two straight lines which may be misinterpreted as an indication of a composite system. This sensitivity to rate is due to the assumptions involved in deriving the pressure diffusivity equation and the improper linearization of the inner boundary condition. On the other hand, the pressure squared approach is insensitive to rate because of the proper linearization of the inner boundary condition and the better treatment of the nonlinear terms when deriving the diffusivity equation in terms of p2.

This paper also discusses the rate normalization of multiphase well tests with varying flow rates, i.e. buildup tests dominated by afterflow, and drawdown tests dominated by unloading effects. The rate normalization, currently used in the industry, is based on the pressure approach which requires that the total rate in RB/D be monitored throughout the test. This is not easily done in practice. Furthermore, this normalization results in underestimated values of total system mobility and yields no individual phase permeability. This paper proposes a new rate normalization method based on the pressure squared approach. The proposed normalization requires only surface oil rates to be monitored. Moreover, it results in reasonable estimates of individual phase permeabilities and thereby an accurate value of total system mobility. A simulated example which demonstrates the applicability of this proposed normalization is presented.
An Analytical Cyclic Steam Stimulation Model for Heavy Oil Reservoirs
Authors: Gozde S. , Chhina H. S. , Best D. A.
Published: December 2007

The cyclic steam stimulation of wells is of great interest in thermal recovery projects, especially in heavy oil reservoirs where steam injectivity can be achieved without hydraulic fracturing.

A number of analytical steam stimulation models have been developed in the past, but no one model can be used for a wide variety of heavy oil reservoirs (i.e. pressure depleted, pressure drive, primary production). A new analytical model for cyclic stimulation of heavy oil reservoirs, which includes pressure drive, has been developed. The model incorporates some of the major recovery mechanisms which are applicable for steam stimulation (i.e. pressure drive, gravity drainage, cold oil influx, relative permeability effects). Simple analytical equations are used to account for the energy and material balance calculations. The model is applicable to both immobile and mobile oil at original reservoir temperatures. The proposed model is a modification and extension of the Gontijo & Aziz model and has additional features beyond the Gozde-AOSTRA model, which include heat loss calculation and wellbore heat losses.

The model is validated through a comparison of the results with available field data. A comparison with another analytical model showed that the proposed model is much better equipped to history match a wide variety of heavy oil reservoirs.
Performance Evaluation of the MOCO T In-Situ Combustion Project, Midway-Sunset Field
Authors: Curtis J. H.
Published: December 2007

This paper describes the analytical methodology applied to the MOCO T reservoir to match 27 years of dry in situ combustion project performance. It also serves to update previous technical papers on the project.

A modification of the Nelson-McNiel Analytical model is introduced that provides excellent agreement with field performance. The correlating factor derived is found to be strongly dependent upon the product of the air requirements and volume burned. Equations and graphical relationships are developed to show the recovery effects of various parameters such as air injected and volume burned.

The calculated combustion front location also agrees well with produced fluid temperature maps. Close agreement between the calculated burned thicknesses and those obtained from recent seismic tomography efforts is also presented.

The paper provides excess air, air-oil ratio, and oil-water ratio calculations as well as numerous graphical relationships that aided in an understanding of the reservoir, and may further improve process efficiency.

These results demonstrate that analytical methods can be applied successfully to history match and predict future performance. It is believed that these results have direct applications to other reservoirs with similar parameters and characteristics.
Validity and Accuracy of Reservoir Simulation With A Two-Dimensional, Three-Phase, Unsteady-State Heterogeneous Matrix Computer Model
Authors: Garrett J.E.
Published: December 2007

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

This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. 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 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.

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.

The validity and accuracy of reservoir simulation with the use of a grid-type numeric model employing explicit-computational procedures is demonstrated. In five separate areas of reservoir engineering technology, comparisons are made between the results of this model and those obtained by means previously adopted by the industry. In all cases, the model's answers compared favorably; in fact, in most cases its accuracy exceeded practical data limitations.

The conclusions reached are that [1] valid solutions can be obtained to a wide range of realistic reservoir problems by judicious use of these models; [2] the accuracy of the explicit-type model used in these tests is well within acceptable engineering tolerances; and [3] such models should obtain good, valid solutions to reservoir situations too complex to be handled by other available means.

Introduction

The latest engineering tool for the advanced study of reservoir performance is the grid or matrix type of numeric reservoir simulation model. By viewing the heterogeneous reservoir as many small homogeneous blocks or cells having different properties, such models are intended to permit accurate analysis of complex reservoir situations of essentially any type.

In recent papers, questions have been raised concerning the relative accuracy of the implicit and explicit pressure solution techniques used in these computer models. Of more value to the engineer, however, is the testing of the accuracy and validity of such models by comparisons with theoretical solutions or with proven analytical procedures to determine their worth, per se, as an engineering tool.
Optimization of Hydraulic Fracturing Treatments Applying Post-Fracture Pressure Analysis for the Upper Clearfork Formation
Authors: Rogers J. D.
Published: December 2007

The technology developed for massive hydraulic fracturing in tight gas reservoirs is applied to create short, highly conductive fractures in the oil productive Upper Clearfork formation of West Texas. The contents of this paper review operational aspects of design and factors influencing the successful execution of fracture treatments during an extensive infill drilling and waterflood expansion program in the Amoco operated Prentice Northeast Unit (PNEU). The PNEU is located in Terry and Yoakum counties of West Texas.

Long Spaced Digital Sonic Log Data (LSDS) was collected on several wells in the Prentice Northeast Unit. This data, along with results of pump-in/flowback and mini-frac tests were used in conjunction with fracture design and economic models to develop an optimum fracture design for this reservoir. Fracture pressure analysis and post fracture pressure decline analysis techniques were used to further refine the optimum treatment design. The optimum fracture design, developed in this manner, was then used to stimulate over 60 wells in this Unit and other Amoco operated Units producing from the Upper Clearfork formation. Results of these fracture stimulations have been excellent.

This paper presents a discussion of the collection of post-fracture pressure decline data, the analysis of this data, and the application to optimize the design of hydraulic fractures in the Upper Clearfork formation. Fracture stimulation design is presented with a framework in which maximization of return on the invested dollar is the ultimate goal.,
Methods to Improve the Efficiency of Rod-Drawn Subsurface Pumps
Authors: Cox B. R. , Williams B. J.
Published: December 2007

A modified sub-surface pump is presented with improved gas handling characteristics, and with the ability to flush sand and small particulate matter away from the leading edge of the plunger. The pump design utilizes a tubular hollow valve rod and precision sizing of the guide to create a low pressure chamber above the plunger on the down-stroke.

The two stage gas and sand check valve installed at the top open cage reduces buckling tendency on long stroke down-hole pumps, and actually eliminates the buckling on shorter strokes and shallow wells.

Buckling of valve rods is discussed and a method cf calculating the buckle point for the various plunger and valve rod sizes, and the longer stroke lengths are presented.

The modified hollow valve rod pump with the two stage gas and sand check valve has actually performed in high gas-oil ratio rod pumped wells, under a packer. Brief case histories are discussed in support of the application of this pump to wells where total fluid is produced through the pump.

A review of the basic API pumps with design advantages and disadvantages in down-hole conditions is given. Accessory items to help the basic pumps in handling gas-sand and corrosion are reviewed. These are economical devices, proven over a period of years, that can be readily applied to standard sub-surface pumps.
Theory of Paleozoic Oil and Gas Accumulation In the Big Horn Basin, Wyoming
Authors: Stone D.S.
Published: December 2007

This paper, to be presented at the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, Houston, Tex., Oct. 1–4, 1967, is copyrighted by the American Association of Petroleum Geologists and will appear in the AAPG Bulletin. Permission to publish any portion of it must be obtained from the Publications Manager of that bulletin. SPE wishes to express appreciation for permission to preprint this paper, and to include it on the program.

A theory of oil and gas accumulation has been developed to account for the relations among stratigraphy, structure and fluid distribution in the oil fields that produce from Paleozoic reservoirs in the Big Horn basin of Wyoming. This proposed theory related the common oil-water contacts observed in the normal multi-zoned Paleozoic anticlinal fields to height of the oil column, formational thicknesses in the crestal area, and number of Paleozoic formations productive of hydrocarbons in each field. The similar chemical composition of the Paleozoic crude oils, and of the associated formation waters, the vertical density stratification of fluids in the multizoned fields with large oil columns, and some unusual reservoir pressure relationships are cited in support of the concept of a common pool state.

The major conclusion of this study is that essentially all of the hydrocarbons held in Paleozoic and Triassic reservoir rocks in the Big Horn basin were generated from the euxinic, dark-colored, organic-rich and phosphatic, finegrained sediments of the marine facies of the Permian Phosphoria formation. Primary migration was probably completed by Early Jurassic time when these hydrocarbons accumulated within regional stratigraphic traps created primarily by updip facies change, pinchout and truncation of the reservoir carbonates of the Phosphoria formation, and also by uneven Phosphoria-Goose Egg truncation of the underlying Tensleep sandstone both locally within the Big Horn basin and further east in the area beyond that was covered by marine Phosphoria rocks.

The hydrocarbons held within these Phosphoria and Tensleep stratigraphic traps were later released as a consequence of fracturing and faulting associated with Laramide folding, and moved into older Paleozoic reservoir rocks until fully adjusted to anticlinal structure in common pools. Vertical segregation of an original common pool into several separate pools was accomplished in some exceptional fields of the basin either by selective hydrodynamic tilting within the Tensleep zone, by leakage or redistribution of fluids through fault zones, or by escape of hydrocarbons to the surface and inspissation resulting from breaching of the original Triassic cap rocks.
Tubing Conveyed Perforating Sucker Rod Pumping Wells
Authors: Holloway M. L. , Wesson D. S.
Published: December 2007

During the development of the San Francisco field near Neiva, Colombia, South America, significant reductions in productivity indexes were encountered when wells were put on artificial lift after being perforated. These wells were completed in the Caballos formations, which typically span over 400 gross ft with 110 ft of net pay and appear to become damaged when exposed to water. Tubing conveyed perforating is the preferred technique due to its advantage of better inflow performance. When retrieving the tubing conveyed guns, aqueous control fluids were used to control some wells prior to running a sucker rod pump. Thus, these high volume wells usually suffered an increase in formation damage which lowered their productivity indexes.

A workable solution to this problem was developed and called a seating nipple bypass assembly. This tool enables conventional tubing conveyed perforating guns and a differential firing head to be attached to the bottom of a tubing string. The tool also contains an 3-½ in. API seating nipple so that a rod pump can be seated and operational when the guns are activated. Thus, a well can be completed with the benefits of using tubing conveyed perforating and immediately commence artificial lift. This achieves greater production rates without damaging the producing formation, as could have happened when controlling the well with aqueous based fluid while reconfiguring the bottom hole assembly.
Spreadsheet-Based Program Helps Solve Variety of Operational Problems
Authors: Hall J. W. , Andrew J. H.
Published: December 2007

A microcomputer spreadsheet-based program has been developed to provide guidelines for dealing with common operating problems right at the wellhead. The spreadsheet uses basic daily production data to establish well-by-well production priorities. These priorities are clearly communicated in a format that eliminates guesswork and inaccurate assumptions and facilitates efficient responses to production upsets. Rapid response to producing problems helps reduce production losses and increases total revenue.
The Theory and Economics of Electrostatic Treaters
Authors: Cummings C. B. , Engelman C. E.
Published: December 2007

Crude oil is rarely produced without some water being present. The water cut in produced fluids from the formation can vary from 0-99%. Most crude purchasers limit the amount of water and impurities that may be included with the oil, typically between 0.2% and 2.0%. The producer must separate the well fluids in order to sell the oil and dispose of the basic sediments and water (BS&W). Emulsified oil and water mixtures require treating to achieve an acceptable level of BS&W content. Heat, chemicals and electricity can be used to break the emulsions in an efficient and expedient manner. Due to lower treating temperatures, electrostatic treaters are often an economical means of dehydrating crude oil, but many times the advantages of electrostatics are overlooked. This paper discusses the basic process and economics involved with treating oilfield emulsions with electrostatics.
Case History Studies: Abnormal Pressured Gas Reservoirs
Authors: Poston S. W. , Chen H. Y.
Published: December 2007

Analysis of geopressured gas reservoirs often times is particularly difficult. The effects of pore volume compressibility as well as the uncertain presence of water influx should usually be included in the calculation procedures. The solution plot method is a straight forward procedure which negates the need for estimating these two troublesome reservoir parameters.

Computer simulation studies have shown variable pore volume compressibility effects exhibited by under-stressed, abnormally pressured gas reservoirs are based on grain expansion as well as pore collapse values. Normally compacted geopressured, gas reservoirs will display uniform pore volume compressibility effects.

The solution plot method permits the simultaneous estimation of the original gas in place, pore volume compressibility values as well as a qualitative estimate of the affect of water influx.
Case History of Restimulations in Western Oklahoma
Authors: Ennis B. K.
Published: December 2007

This paper presents the results of a restimulation workover program performed in Western Oklahoma during the last two years. The restimulations were selected from wells which were not producing at peak rates based on log development and post-frac pressure buildup tests.

The restimulation workovers have generated sufficient incremental cash flow to payout the entire program in eight months. Pre-workover and post-workover production rates in conjunction with workover costs are presented to justify the economics for the restimulations.
Laboratory, Computer Modeling, and Field Studies of the Pulse Fracturing Process
Authors: Schatz J. F. , Zeigler B. J. , Hanson J. M. , Christianson M. C. , Bellman R. A.
Published: December 2007

A combined testing and modeling program has been completed with the purpose of providing systematic observations and models of the pulse fracturing process. Approximately eighty individual laboratory tests have been successfully carried out in blocks of scaled rock simulant loaded to a true three-dimension stress state with miniature propellant/explosive charges in a wellbore as the fracturing energy source. Real-time borehole pulse pressure measurements were also obtained. Mathematical models developed include descriptions of borehole pressurization, flaw initiation, gas-driven fracture propagation, and fracture arrest. Measurable material and natural parameters such as moduli, gas permeability, and in situ stress are used in the models. Models include true crack-crack interaction. One of the models is fully two-dimensional and includes fracture curvature in an anisotropic stress field. Results indicate that multiple fractures are created over a broader range of source, material, and natural conditions than had commonly been thought before, but that the conditions conducive to extremely long fracture extension, usually considered desirable, are somewhat difficult to establish and maintain. Several approaches to optimizing and evaluating the process in the field are suggested, including a possible approach to the generation of long fractures. A field test observation is described.
New and Unusual Applications for Plunger Lift System
Authors: Beauregard E. , Morrow S.
Published: December 2007

As plunger systems become more sophisticated and people become more familiar with them, their credibility and usage is increasing. As a consequence, the spectrum of applications for these systems has begun to increase.

In the ongoing pursuit of lower lifting costs and reduced capital spending, creative engineering techniques have applied the principle of the plunger to some unique production problems. The purpose of this paper is to present a number of these along with some case histories.

The normal applications for a plunger are for Gas Wells, Hi-Ratio Oil Wells, Intermittent Gas Lift and Paraffin Removal.

Now, however, plungers are also being used to:

Produce liquids in extremely low pressure reservoirs Produce liquids in retrograde condensate wells Remove water from coal seam methane gas wells Prevent paraffin buildup in dual zone wells Prevent paraffin buildup and increase lift efficiency in deviated gas lift wells with wide perforated zones Remove liquids from wells with no tubing Prevent down hole freezing problems in high pressure gas wells Remove water from wells in CO2 injected formations

Another application that appears to be highly probable is liquid removal from CO2 source wells.

The major obstacle to more widespread utilization of plungers has been a lack of education. This has been a problem not only with operational personnel, but engineering and management as well.

Hopefully, these additional applications along with the present increase in usage will make people even more cognizant of the potential savings offered by the plunger lift system.
AL: An Expert System for Selecting the Optimal Pumping Method
Authors: Heinze L. R. , Thornsberry K. , Witt L. D.
Published: December 2007

AL (Artificial Lift) is a software program for selecting the pumping processes best suited to an oil well. It integrates an expert system which manages the knowledge of the subject and organizes the implementation of a set of algorithmic programs for making technical assessments. AL was developed at the University of Missouri-Rolla, Petroleum Engineering Department. This article describes in detail the expert-system part and gives an example of the use of the complete system.
Root Locus Stability Analysis of a Flowing Oilwell Feedback Controller
Authors: Blick E. F. , Nelson A. B.
Published: December 2007

Some naturally flowing oil wells will experience flow instabilities (heading) characterized by regular or irregular cyclic variations in tubing pressure and flow rate. To analyze this phenomena, the unsteady equations of motion for flow are solved by the LaPlace Transform method. This analysis produces a characteristic equation whose coefficients allow one to determine if a particular well is stable or unstable. If the well is unstable it is possible to use a feedback controller which varies the tubing head choke diameter to stabilize the well. By use of the root locus method, various combinations of proportional, derivative and integral controllers are shown to theoretically control some unstable wells.
Gas Turbine Driven Centrifugal Pumps for High Pressure Water Injection
Authors: Neal J.C.
Published: December 2007

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

This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. 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 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.

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.

The experience of Gulf Oil Corp. in the installation and operation of gas turbines as prime movers for centrifugal pumps in high pressure water injection leads to the following conclusions:

Installation of gas turbines and centrifugal pumps can be made with very little difficulty. Only a fraction of the foundation is required for this type of installation as compared with other types using heavier equipment. Vibration of equipment and piping is practically eliminated. It is felt that where low cost gas is available, two-shaft gas turbines driving centrifugal pumps are an economical and flexible high pressure water injection installation. Centrifugal pumps normally require less attendance than plunger pumps. Station construction costs compare favorably with other stations utilizing different types of prime movers and pumps. Centrifugal pumps can be designed for almost any condition of high pressure water injection, but there are certain conditions in which plunger pumps are more economical. When the volumes are low and the head high, plunger pumps are usually more economical. Gas turbines are easily automated for unattended operation. Several operating problems were experienced, but subsequent modifications now have provided for a highly satisfactory operation. Fuel consumption compares favorably with that of other types of gas engines. Maintenance and repair cost of the pump has been much lower than anticipated and gas turbine costs have been slightly higher than originally anticipated. The over-all operation is economically attractive.

Introduction

Four gas turbine engines are driving multistage centrifugal pumps for injection of high pressure water into Gulf Oil Corp's Goldsmith 5600' field, Ector County, Tex.
A Generalized Approach for Analyzing the Early-Time Pressure Transient Data
Authors: Duong A. N. , McLauchlin L. A.
Published: December 2007

This paper describes a computer-aided interpretation approach that can be used to analyze the early time data of a transient test with wellbore storage and skin effects. Pressure derivative, pressure response and pressure cumulative are used to rearrange the convolution integrals into a linear relation of three variables. The coefficients of this relation are related to the model parameters of reservoir properties, wellbore storage constant and skin factor. A linear multiple regression is performed for these variables to obtain the optimal values for the model parameters. Once the model parameters are known, the calculation of pressure change can be performed for each flow regime assumed. The statistical and graphic analyses will be used to check the results, as well as the accuracy, of each flow regime assumed. This approach is simple. However, it requires that the reservoir response function does not change and the model parameters are constant during the analyzed period.

The advantages of this computer-aided interpretation approach are that the early time data can be analyzed numerically and the approach can be applied for any type of flow regime; i.e, radial, linear, bilinear and spherical flow.

A real data example is used to demonstrate the application of the proposed approach.
On the Design of Fracture Acidizing Treatments
Authors: Gdanski R. D. , Lee W. S.
Published: December 2007

A fracture acidizing simulator has been written which incorporates many of the recent advances in fracture geometry and temperature calculations and the acid spending process with the many complex variables which affect acid spending. All the various effects have been coupled to reduce errors and improve simulation. A procedure which should effectively correlate laboratory acid-etched conductivity tests with anticipated field results has also been introduced.
Drillable Service Packer Systems Increase Well Service Versatility
Authors: Hushbeck D. F. , Streich S. G.
Published: December 2007

Cement retainers have changed very little in the past 10 years, but represent well developed technology. Their biggest shortcoming is a lack of versatility in that they are designed strictly for remedial cementing operations.

A new generation of drillable packers is becoming available to combine the convenience of drillability with the versatility of large bores and multiple valve options. These drillable service packers (DSP) will help fill the gap between drillable cement retainers and retrievable service packers. DSP are designed to give versatility so that time and money can be saved.

DSP will use valving similar to that in drillable cement retainers, which have been used for many years to control pressure and placement of cement during remedial cementing operations. This valving offers downhole pressure control that is not readily available with retrievable packers. This pressure control could be useful in operations outside remedial cementing to provide control before, during, and after testing and stimulation operations. Drillable service packers will allow for testing, treating, and squeeze operations to be performed through a single packer. This feature is extremely cost effective for both drilling and workover operations.

This paper will explore the use of drillable service packers and possible applications of this new downhole technology.
New Fluid-Loss Additives for Oilfield Cementing
Authors: Crema S. C. , Kucera C. H. , Konrad G.
Published: December 2007

The proper cementation of a liner is an operation essential to the completion of an oilwell. A low fluid loss rate is required to prevent setting of the cement slurries before proper placement is achieved. Modified natural polymers are, at the present time, the most common fluid loss additives. However, temperature instability, retardation and high viscosity of the cement slurries are undesirable side effects of these additives. We have synthesized and tested a series of polymers and copolymers to identify potential fluid loss additives and to study the effect of various substituents on the effectiveness of the final material. Measurements of fluid loss, free water, rheology, thickening time and compressive strengths show that the developoment of good fluid loss control additives for cement depend upon careful control of copolymer composition and molecular weight.
Field Compressors for High Pressure Gas Injection Service
Authors: McCutchan Jerry M.
Published: December 2007

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

This paper was prepared for the 42nd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Oct. 1–4, 1967. 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 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.

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.

This paper was formulated to assist production engineers with the design of unattended field gas compressor installations.

With the increasing use of field gas compressors in oil recovery, it is anticipated that the data in this report can be used to decrease the expense caused by usual experimentation in equipment and design for the initial compressor installation.

Experience gained in the design and installation of the Cities Service Oil Co. Dora Roberts Ranch Devonian unit and Virey Ellenburger gas injection projects, as shown on Fig. 2, was utilized. A general layout of a typical compressor installation is included as Fig. 3 and should be referred to as this paper is read.

Gas injection was begun in the Devonian unit in May, 1961, and in the Virey field in Jan., 1966. Because of the high revenue potential and the long productive life of these fields, slow speed, integral, gas engine driven compressors were selected. Since the injection locations are numerous and the predicted injectivity pattern indicated possible future changes, the advantages of having this equipment completely packaged was utilized.

Compressors with hp ratings of 180 and 330 were selected to best fit the required injectivity rates. These compressors were designed to boost 1,800 psig residue gas to discharge pressures up to 7,500 psig.

A survey of 21 gas compressors totaling 4,380 hp in the two fields was made for 1966. Average operating conditions were 1,800-psig suction and 5,800-psig discharge pressures. During 1966, these compressors handled 16,874,639 Mcf of gas. The average downtime for these packaged units for routine maintenance was 1.2 percent. Compressor maintenance expense averaged $19.12/hp. Compression cost, excluding depreciation, averaged 0.933 cents per Mcf.

The 180-hp compressors operated at 550 rpm and the 330-hp compressors operate at 400 rpm. The survey showed less downtime for routine maintenance for the 330-hp compressors, thus indicating the advantage of the slower-speed equipment.