bluuebunny/crossref_metadata_2025 huggingface dataset:
On the Effect of Viscosity and Sand Thickness on Kern River Field, Single-Zone, Steamflood Performance
Authors: Restine J. L.
Published: December 2007

Since the early 1960's, steamflooding has been completed in 1,600 five-spot 2-1/2 acre (10,000 m2) pattern zones in the Kern River Field. The data from 61 completed projects (averaging 25.8 patterns per project) and 91 cored postflood zones has been used to develop a correlation to predict oil recovery for a given gross sand thickness, oil viscosity, and initial oil saturation.

This correlation to predict oil recovery is based on the injection and operating strategies in past use, and changes that have been made in those strategies may result in higher recoveries. In several Projects, average pattern size 4.0 acres (16,000 m2) and 50 feet (15 m) thickness, initial injection rates of 500 BWPD (3.3 m3/hr) were sustained past steam breakthrough. These initial past steam breakthrough. These initial injection rates may have been too high and perhaps should have been reduced at steam perhaps should have been reduced at steam breakthrough.
Current Status Of The Duri Steamflood Project Sumatra, Indonesia
Authors: Pearce J. C. , Megginson E. A.
Published: December 2007

The Duri Steamflood (DSF) Project is the largest thermal enhanced oil recovery (EOR) project in the world, surpassing in production both the Kern River and Belridge Fields in the San Joaquin valley of California. The field is located in Riau Province, on the island of Sumatra, in Indonesia. Duri is the second largest field in the country, producing nearly 200,000 BOPD of steamflood production. The field is operated and developed by P.T. Caltex Pacific Indonesia (CPI), a production sharing contractor to Pertamina, the Indonesian national oil company.

The DSF Project will develop over 15,000 acres of reservoir utilizing over 4,000 producing wells. At present, only about one third of the field is under active steamflood. The DSF Project is divided into twelve development units called Areas. New Areas are about 1,400 acres in size, and are developed, that is, drilled and put on injection, in about 1-3/4 to two years.

The steamflood development involves the use of symmetric patterns of varying size and configuration. Inverted seven spots, approximately 11-5/8 acres in size have been the principal pattern configuration for Area development, including the Area currently being drilled [1]*. For future Areas, inverted five and nine spots, approximately 15-1/2 acres in size are planned. This change has been implemented as a result of detailed reservoir simulation studies conducted in CPI [2,3].

The Duri Steamflood Project is unique in that it simultaneously involves the management of existing steamflood Areas, the development of new steamflood Areas, and the design of future Areas to maximize both oil recovery and production efficiency. The balancing of these three objectives is both a complex and vitally important project management task. The approach taken by CPI is a multi-disciplinary one involving development geology, petroleum engineering, and surface facility engineering. Improvements in well stimulation techniques, well completions, flood monitoring and flood design have been realized.
San Ardo Field Production Testing System Upgrade
Authors: Christianson B. A. , Berger E. L.
Published: December 2007

In 1985, as part of a field-wide upgrade of surface facilities, Texaco's San Ardo field engineers began an extensive program to improve the quality of the field's production testing systems. Analysis of the existing systems showed that they were capable of delivering tests no more frequently than once per well per month, while the field's gauge factor ranged by ±40%. Moreover, component reliability, layout, and process control made hardware troubleshooting, maintenance, and repair difficult and slow.

The program that was completed nearly three years later created a production testing system, which while outfitted with 83% more testing equipment, delivered a fivefold improvement in testing frequency. Gauging variability was reduced to one eighth that of the replaced systems.

This paper discusses the project accomplishments in hardware design, process control, and the operator interface, which have significantly improved the quality of Texaco's San Ardo field production operation.
Heavy-Oil Dehydration Facility Retrofitted With Computer Monitoring
Authors: Strome R. K. , Beal K. P.
Published: December 2007

The largest oil-fired oil dehydration plant in America was partially retrofitted with a state-of-the-art computer monitoring and data acquisition system. This paper describes Phase I of that system, and the benefits obtained. The new operator-interface software and future Phase II expansion plans are also discussed.
Recovery Mechanisms: Fireflooding a High-Gravity Crude in a Waterflooded Sandstone Reservoir; Countess Field, Alberta
Authors: Metwally M.
Published: December 2007

This paper summarizes the results obtained from laboratory and field tests conducted for the Countess "B" Fireflood Project, and attempts to explain the recovery mechanisms of the fireflooding application in a waterflooded Glauconitic Sandstone reservoir of the Upper Mannville Group containing a 28°C API crude in southeastern Alberta.

Results of coreflood tests, combustion tube tests and field observations, suggest that combustion gas drive supported by efficient displacement from the burned volume is the most important mechanism in fireflooding the Countess "B" Pool and the propagation of combustion gas and water ahead of the firefront is of considerable importance for oil recovery. Laboratory observations from coreflood tests confirm that combustion gas was equally important in recovery both before as well as after breakthrough and oil production response due to fireflooding occurs almost immediately after initiating air injection. The history of the combustion gas composition and properties of the produced oil, which are not significantly different from those of the native oil, indicate the existence of a stable high temperature region and low temperature oxidation reactions. Analyses of recombined oil and gas samples simulating in-situ fireflooding conditions, indicate favorable mobility under fireflooding.

The Pilot Project is operated by PanCanadian Petroleum Limited, jointly owned with LL&E Canada Limited and supported by the Alberta Oil Sands Technology and Research Authority. The Pilot Project was initiated in 1983 and still continues. It is currently being expanded to a prototype commercial project.
Thermal Conductivity Estimation From Temperature Logs
Authors: Seto A. C. , Bharatha S.
Published: December 2007

Heat losses to over/underburden play an important role in determining the efficiency of a thermal oil recovery process such as cyclic steam stimulation. Thermal conductivity is a key parameter for evaluating heat losses. Since there is generally little information concerning in situ thermal conductivity values, it is often assumed in reservoir simulation models that the reservoir and its over/underlying formations possess the same value of thermal conductivity. If the over/underlying formations possess significantly higher values of thermal conductivity compared to the reservoir, the heat losses will be underestimated in calculations based on uniform thermal properties. Systematic procedures to estimate thermal conductivity values from temperature logs and core measurements are presented in this paper and applied to field and laboratory data.
Applying a Novel Steam-CO2 Combination Process in Heavy Oil and Tar Sands
Authors: Clampitte R. L. , Eson R. L. , Cooke R. W.
Published: December 2007

It is estimated that there are 85-110 billion barrels of heavy oil reserves in the U.S.. Since the 1960's, steam has been the predominant Enhanced Oil Recovery (EOR) method for these high viscosity, heavy oil reservoirs worldwide. However, some experimentation utilizing immiscible carbondioxide injection in heavy oil reservoirs has shown encouraging results. This paper documents the efforts of a 2-1/2 year, two phase project conducted in the Midway-Sunset field of California applying a novel steam/carbon-dioxide combination process to recover heavy oil.

In many instances in thermal recovery projects, steam channeling and/or steam override reduces the efficiency of the process. This inefficiency has been corrected, or at least somewhat mitigated, through the use of steam foams. A cost effective alternative to foams was developed as part of the research phase of this project. A high temperature, stable polymer gel/surfactant solution has been developed and has proven in field tests to be extremely effective at diverting steam from steam channels and the override zone to areas of the reservoir higher in oil saturation. By accomplishing this diversion, it allowed carbon-dioxide, injected along with the steam, to enter a potentially more productive portion of the reservoir. During the 2-1/2 years of the project, nine cyclic steam stimulation wells and two continuous steam drive injection wells were treated with the novel EOR process.
Well Visualization and Analysis
Authors: Podio A. L. , McCoy J. N.
Published: December 2007

A system has been developed based on a powerful portable microcomputer and an integrated data acquisition package which allows real-time visualization of pumping well performance.

The system combines all the necessary elements to obtain a complete analysis of the performance of the pumping system which includes the pumping unit, the wellbore, and the reservoir.

The data acquisition package is connected to the expansion slot of the computer and consists of the necessary analog and digital channels to process data from standard transducers such as acoustic, pressure, temperature, rod load, displacement. etc. Detailed surface unit performance curves such as dynamometer, speed, acceleration, power etc. can be obtained and analyzed. When the instrument is used in conjunction with an acoustic pulse generator and receiver, it digitizes and stores the reflected acoustic signals which are digitally filtered and automatically processed to determine the liquid level. This is undertaken under program control so that a continuous recording of fluid level vs. time is obtained along with the pumping unit performance parameters.

Fluid level data is processed by the software to calculate bottom-hole pressure as well as flow into and out of the well bore. Changing the well from flowing to shut in conditions allows recording of pressure buildup data which is then interpreted in terms of reservoir parameters.

The Well Visualization display can be used as a diagnostic tool to optimize pumping well performance on a periodic basis. The present performance of the well is compared to its recorded past performance and in the case where significant differences are noted, a more detailed analysis is undertaken to recommend changes in operation or remedial actions. In critical well applications, the system can function as a stand-alone dedicated controller.
Net Pressure Fracture Design
Authors: Poulsen Don K.
Published: December 2007

By substituting net pressure values for the fluid mechanics of typical fracture growth calculations, numerical models for calculating fracture growth from these pressures, using any of three popular fracture width equations, have been developed. One model uses expected net pressure behavior, ideally obtained from a similar treatment in an offset well, to predict fracture growth for design calculations. A second model uses collected pressures and injection or flowback rates to calculate fracture dimensions over time, allowing fracture behavior to be monitored during a treatment or analyzed afterward.

The governing equations for these models were examined under specific conditions, leading to guidelines for interpreting fracturing pressures under a variety of conditions.

And, by considering fluid mechanics, as well as fracture mechanics and a volume balance, expected pressure behaviors for power-law fluids in all three fracture geometries have been determined.
Slug Testing for Pumping Wells
Authors: Kabir C. S.
Published: December 2007

This paper proposes a variation of ‘slug test’ for sucker-rod pumping oil wells. Application of slug testing simply expedites the buildup process. A slug test is conducted by admitting a slug of reservoir liquid such that the hydrostatic head of the wellbore liquid column balances the reservoir pressure; that is, the well kills itself. Bottomhole pressures (BHP) monitored in such a test have been routinely analyzed by the hydrologists and petroleum engineers alike over the past 35 years.

Although a slug test is typically associated with a new well, the same concept can be extended to pumping wells producing for years. A variation of slug test can be conducted on a pumping well by leaving the casinghead valve open and recording pressures either downhole or by using the acoustic method. The data so gathered lends itself to slug test interpretation.

An analysis of wellbore storage phenomenon arising from flow of a two-phase gas/liquid mixture is presented. The analysis shows that a slug test would allow the pressure buildup process to occur much faster than the conventional buildup method wherein a surface shut-in is required. Two tests conducted on the same well by the two methods, using downhole recorders, demonstrate the value of the proposed method. Reservoir parameters computed from the two tests are in very good agreement; thus, lending credence to the method proposed.
Scale Inhibitor Evaluations and a Mechanism of Inhibition of Sparingly Soluble Salts
Authors: Tomson Mason B. , Matty J. , Oddo J. E.
Published: December 2007

Scale deposited within production systems associated with high volumes of produced brine can pose serious problems to the operator both in field economics or in the total loss of production. Seven barrels of oilfield brine are produced for every barrel-equivalent of energy obtained in the United States each year and with the advent of enhanced recovery methods, this ratio can be as high as thirty or fifty to one.

Many inhibitors have been in use for over fifty years, but no quantitative explanation for their effectiveness has been available. A general theory of inhibitor effectiveness and mechanisms of action are presented and two mechanisms based on diffusion rates are proposed with associated equations.

Many scale inhibitors are currently on the market primarily based on phosphonates, copolymers or polymaleates. An inhibitor evaluation apparatus developed at Rice University has gained wide acceptance in the petroleum industry and will be described. The results of inhibitor evaluation tests in various brine systems will be discussed in conjunction with the theory of inhibitor effectiveness. Results are presented for CaSO4 and CaCO3.
Continuously Gelled Diesel Systems for Fracturing Applications
Authors: McCabe M. A. , Terracina J. M. , Kunzi R. A.
Published: December 2007

An efficient system of running gelled diesel stimulation fluid has been developed which allows continuous treatment and requires no pregelling or batch mixing. Continuous gelling while pumping is possible with this unique system, which is a combination of phosphate ester chemistry and computer-controlled metering incorporated in a mobile trailer or preblender. Operational and environmental advantages have been reported after field applications of this system.

Stimulation treatments using gelled oil as the fracturing fluid have been routine for many years. Most of these treatments have been performed by batch mixing gelled oil in storage tanks before pumping it into the formation. This, however, can result in costly waste of premixed gel should the job be cancelled or terminated prematurely. The system discussed in this paper gels the fracturing fluid while it is being pumped downhole, to eliminate the disposal problems associated with batch mixing;

The preblender is capable of mixing at 10 to 40 bbl/min and metering two liquid additives (phosphate ester gellant and activator) into the diesel. The automated equipment can be used to vary the concentrations of the additives, gel viscosity, or job volume in realtime at any point during the job without wasting gel.

Environmental and operational advantages of running gelled diesel continuously include (1) no left-over gel in tank bottoms to dispose of after the job, (2) pre-gelling time saved, (3) operators pay only for materials actually used during the job, and (4) elimination of the difficult task of withdrawing highly viscous, batch-mixed gels from storage tanks.

In Alaska, several wells have been hydraulically fractured using the technique. The diesel-based gel is found to be preferable to water-based gel systems in areas where temperatures can reach well below the freezing point. The equipment of this system is also designed to withstand arctic conditions.

This paper describes the fluid system as well as the equipment design and metering criteria for the continuous gelled oil system. Field application cases of this system will also be presented.
Chaos: A Source of Miscible Viscous Fingering Instabilities
Authors: Fanchi John R. , Shank G. Deane , Christiansen Richard L.
Published: December 2007

Previous theoretical researchers successfully generated viscous finger patterns by assuming a randomly distributed boundary condition in their numerical models. Our objective is to identify a natural source of the randomness that underlies their success. A source of fluid flow instability is discerned by viewing fingering as a chaotic (nonlinear dynamical) phenomenon.

We begin by showing that miscible displacement models can be expressed as nonlinear generalizations of the linear convection-dispersion equation. A nonlinear dynamical analysis technique is used to study the stability of the nonlinear system. Detailed study of several ID and 2D cases illustrates the applicability of the stability analysis.
Importance, Genesis and Recognition of Fracture Permeability in Fruitland Coalbed Methane Reservoirs of the Northern San Juan Basin, Colorado and New Mexico
Authors: Close Jay C. , Mavor Matthew J. , McBane Richard A.
Published: December 2007

Fracture permeability is inferred to be the most important influence on productivity of natural gas from commercial Fruitland Formation coalbed methane reservoirs in the Cedar Hill, Northeast Blanco Unit, and Ignacio Blanco fields of the northern San Juan Basin of Colorado and New Mexico. Reservoir deliverability in these areas with significant coalbed methane resources and reserves is less influenced by thickness, depth, completion technique, and measured and inferred pressure and formation damage.

Cleats (coal fractures) in cores from four northern San Juan Basin Gas Research Institute Fruitland evaluation wells in these fields formed during coalification in strain fields imparted as a result of Early Tertiary Laramide and Late Tertiary-Recent Rio Grande Rift regional tectonic episodes. These cleats are not the result of sedimentary compactional folding. The presence of discrete, very thin interbedded layers of Fruitland coal and non-coal ("ash") lithotypes with different respective rock mechanical properties favored brittle deformation of coal layers. Many commercial Fruitland wells are located in areas with extremely minor true structural flexure (folds), which indicates cleat permeability is largely a function of coal composition.

Knowledge concerning fracture permeability will influence further delineation and development of northern San Juan Basin Fruitland coalbed methane resources and reserves. The following procedure for qualitative recognition of areas with greater Fruitland permeability prior to drilling is suggested. 1. Preliminary collection and analysis of reservoir description and supporting geological and engineering data from in-house files and public literature should be completed. 2. The geologic setting of available acreage should be determined through interpretation of stratigraphic and structural maps and cross sections. 3. Favorable locations within acreage blocks should be delimited through interpretation of a). available drill stem test data, and b). gas and water production rate maps and data with respect to completion techniques and formation damage. 4. These areas of interest should be analyzed to find potential drilling locations by finding specific sites that a). required higher Fruitland drilling mud density to prevent blowouts using mud logs, drilling records and mud density maps, and b). have Fruitland coal waters with relatively low total dissolved solids (salinity) and chlorine ion concentrations. 5. Once a drilling location has been selected, potentially producible coal zones can be determined a). through identification of coal intervals with densities between 1.2 and 1.75 g/cc on open hole high resolution density logs, and b). by identification of coal intervals with drilling mud invasion through interpretation of micrologs and resistivity log suites from offset wells.
Prediction Of Pore Pressure From Penetration Rate
Authors: Combs George D.
Published: December 2007

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

This paper was prepared for the 43rd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Sept. 29-Oct. 2, 1968. 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.

A general equation for penetration rate in shales is formulated, and the constants in the equation evaluated by a regression analysis of penetration rate data from six Offshore Louisiana wells. The correlation assumes that penetration rate is proportional to weight on the bit, rotary speed, and a hydraulics term, each raised to a fixed power. A penetration rate normalized for changes in these variables is found to decrease with increasing differential pressure and with increases in a tooth wear index. The drillability of shales defined as the drilling rate at some standard operating condition decreases with increasing depth but increases when the pore pressure increases because of the reduced compaction.
Prevention of Paraffin Well Plugging by Plunger-Lift Use
Authors: Narvaez C. , Ferrer A. A.
Published: December 2007

This paper describes a field project currently in progress in Corpoven's Anaco District, Eastern Venezuela. Corpoven S.A. an operating affiliate of Petroleos de Venezuela (PDVSA) has experienced production difficulties with paraffin deposition in natural flow and gas lift wells. A series of field tests were therefore devised to evaluate specialized plunger lift applications in problem wells. The objective of these tests was to investigate lifting techniques that would minimize existing paraffin removal costs involving wire line mechanical scraping of depositions in the production tubing and hot diesel fuel injection for solidified wax removal. During 24 months of continuous field testing, results indicated the possibility to keep affected wells on production using a plunger lift piston to dynamically remove precipitated wax in a relatively short cycle operation. Usefull production life between workovers has been dramatically increased while operating costs were correspondingly reduced. Response has been very positive in wells where various field options involving plunger lift technology have been completed. The method will have been extended to 17 additional wells by the end of 1990. Preliminary results to date indicate a similar success rate to that of the previous tests.
Refracture Stimulations in the Norge Marchand Unit: A Case Study
Authors: Branch G. A. , Drennan K. M.
Published: December 2007

This paper presents the results of a restimulation workover program in the Norge Marchand Unit performed during the past seven years. Upon initial completion these wells were fractured with Ottawa sand. It was suspected that a loss in fracture conductivity had occurred as a result of the proppant crushing due to the high closure pressure (7000 psi). In an effort to improve the fracture conductivity, the wells were refractured using intermediate strength proppant. The use of pressure buildup tests to select restimulation candidates improved the likelihood of having a successful treatment. The successful refractures resulted in an average increase of 50 B0PD and 98 MB0 additional reserves per well.
The Next Generation of Foam: A Field Study of Northwestern Oklahoma Foam Fracturing
Authors: Toney F. L. , Mack D. J.
Published: December 2007

Foams have been used as hydraulic fracturing fluids for over twenty years. Their primary usage is in reservoirs that are under-pressured and/or water sensitive. Nitrogen was the gas initially used as the internal phase. Later, carbon dioxide became more widely accepted and provided better load recovery and production.

Now, a third generation of foams has been developed. Nitrogen and carbon dioxide used simultaneously as the internal phase has shown to further improve load recovery and production rates.

This paper will present a brief review of foam fracturing procedures and mathematics, monitoring hardware and software requirements, rigging up and safety requirements. The majority of the paper will center on foam fracturing treatments performed on low permeability reservoirs in Northwestern Oklahoma. A comparison of past and present treatments and production rates utilizing operator supplied logs and production data will be presented. Overall, the new Binary Foam treatments have shown to be beneficial from a treatment application viewpoint. Advantages include (reduced screenouts), increased load water recovery, decreased flaring time due to lack of pipeline acceptable gas and improved production rates.
Analysis of Fann Model 50 for Fracturing Fluid Rheology
Authors: Gdanski R. D. , Harris P. C. , Lord D. L. , Reidenbach B. , Shah S. N.
Published: December 2007

Rheological measurements of a typical delayed titanium crosslinked hydroxypropyl guar (HPG) fluid were made with crosslinking reactions occurring under controlled shear rates (40, 120, and 170/sec) and heating rates (4 and 8°F/min and preheated bath). Five different bobs were used, showing the effect of gap width and percentage of total fluid within the gap. Some bob-cup combinations allowed the gel plugs formed in low shear rate conditions to easily circulate back into the gap and influence subsequent fluid viscosity. Other combinations allowed little circulation or had minimal plugs. As a result of this study more accurate fluid rheology measurements can be made with the Fann Model 50 viscometer if a realistic thermal and shear history are used, along with a bob-sleeve combination which maximizes the fluid contained within the gap and minimizes circulation of gel plugs back into the gap. Application of the findings in this work will help reduce the large differences typically observed between laboratories testing crosslinked fluids.
An Engineering Interpretation of Seismic Data
Authors: Pennebaker E.S.
Published: December 2007

The reflection seismograph has long been the most important means for obtaining subsurface information prior to drilling. Interpretation of the seismic data is normally made by geophysicists to define subsurface structure. However, considerable information of great value to the drilling engineer is also contained in the seismic information. This paper discusses how the drilling engineer can use these data to estimate depth and magnitude of subsurface formation pressures, predict gross changes in lithology, and warn of possible drilling problems. Techniques are also presented for predicting relative drillability and fracture gradients in rank wildcat areas.

The predictive techniques described have been used with good results over a wide area along the Texas Gulf Coast including Continental Shelf locations and might possibly be applicable to any sedimentary basin.

INTRODUCTION

The only means of obtaining subsurface information other than from drilling is by geophysical prospecting. Although the seismograph has been used by geophysicists and geologists for many years to help define subsurface structure, it is only recently that engineers have begun to discover useful applications.

One of these applications is the use of routine seismic field data to predict both the depths to abnormal pressure formations and approximate pressure magnitudes.1 The predictive method results from the fact that velocities between subsurface reflecting layers can be obtained from seismic field data using well known geophysical techniques. Differences in interval velocities between these layers can be used to develop an average interval travel time (reciprocal of interval velocity) profile, which is in effect an acoustic log averaged over fairly long (500' - 1000') vertical intervals.

Analysis of numerous well velocity surveys revealed a close correlation between interval velocity (interval travel time), and factors such as lithology and degree of rock compaction and that interval travel time varies exponentially and predictably with depth. Departure from this normal trend signifies abnormal pressure or gross lithologic changes.
Utilization of Submersible Pump Systems in Southwestern Venezuela
Authors: Torres G. J.
Published: December 2007

The use of submersible pumps was first introduced to Venezuela in the state of Barinas during 1958. This area of operations is currently assigned to Corpoven S.A., an operating affiliate of Petroleos de Venezuela. Corpoven's Barinas District is made up of two areas. Barinas and Apure which produce some 105 MBPD, 45 MBPD of which is dependant on electrically driven submersible pumps installed in 35 wells. Crude from these wells reflect highly undersaturated reservoirs with oil gravities ranging from 18-30 deg. API and solution gas oil ratios of 50 to 200 SCF/STB. The primary production mechanism present in virtually all reservoirs is a strong water drive that maintains bottom hole pressures at relatively constant levels.

Sedimentary facies for the Barinas reservoirs indicate highly compacted sands interspersed with cementi tious material, while the Apure area reservoirs are characterized by compacted sands with little or no cementitious content.

The present work seeks to identify and document Corpoven's operational experiences and results in the utilization and operation of downhole electro-submersible pumps. Special attention will be drawn to the handling of produced BS&W (sand/sediment), as well as to the problems encountered with calcareous (Ca2C03) deposits. The unique effects of up and down thrusts on pump impellers will be cited, along with the resulting variations caused to well production by pump frecuency changes enacted to reduce maintenance down time and extend useful pump life. Operational procedures regarding preventative maintenance to the well's electrical power supply, and the resulting sand deposition between pump impellers and diffusers during this down time will also be analyzed.
Predicting Skin Effects Due to Formation Damage by Fines Migration
Authors: Ohen H. A. , Civan F.
Published: December 2007

Among the important issues concerning formation damage assessment and control studies are to understand and describe effectively the physicochemical and hydrodynamic factors controlling near wellbore damage during well development and reservoir exploitation. The problem is twofold. First, the mechanisms responsible for formation damage require complicated mathematical models. Second, it is difficult to simulate near wellbore flow conditions in a laboratory core flow test.

In a paper presented previously, effort has been made by the authors to solve the first problem. The present work is aimed at providing solutions to the second problem. Laboratory core data and the Ohen and civan model have been employed to determine the parameters that control formation damage for given rock / fluids systems and operating conditions. A mathematical technique has been developed to scale the laboratory response to near wellbore conditions-thereby simulating the actual radial flow conditions that exist in the near wellbore region. The radius and permeability of the damaged zone are computed as functions of exposure time of the zone of interest to the damaging fluids. A factor, herein referred to as the skin factor, is computed as a measure of the overall effect of formation damage on productivity or injectivity.

The major benefit of this work is the ability to design drilling and completion operations to optimize the time the pay zone is exposed to the damaging fluid. The validity of the model has been demonstrated in an earlier publication. A typical example is presented in this study to demonstrate the capability of the radial flow simulator to assess formation damage in the near wellbore region. The simulator presented in this study can be used in the design of well development and reservoir exploitation programs with reduced formation damage as well as cleanup operations.
Application of Electric-Driven Reciprocating Compressors for Low-Pressure Gas Well Compression
Authors: Elmer W. G.
Published: December 2007

The installation of electric motor driven reciprocating compressors was chosen instead of gas engine driven integral reciprocating compressors for eight Oryx Energy Company operated gas wells in Harper County, Oklahoma. The three main reasons for this decision were lower initial investment, decreased maintenance and downtime, and consideration of future emission regulations. Design choices for the electric driven compressors are presented.
Gas Hydrates: Occurrence, Production, and Economics
Authors: Iseux J-C.
Published: December 2007

Gas Hydrates – Occurance, Production and Economics

Gas hydrates are crystalline compounds stable under particular conditions of low temperature and high pressure. Relatively large quantities of methane can be trapped in small volumes of hydrates, which represent a substantial in-situ natural reserve and ressource in the shallow crust.

In order to recover natural gas from this resource, it is necessary to dissociate the water structure and remove the gas. This is the reason why a new method is put forward:

Hot Solvent Stimulation after Hydraulic Fracturing, with a method called S.T.S.F. The technique resembles Acid Fracturing but replaces Acid by Hot Solvent for the hydrate dissociation. Moreover, the method can be improved by drilling a second production well in order to control the solvent flow in the fracture and the gas production. The shape of the fracture can be either horizontal or vertical depending on the depth and the in-situ stresses.

The following paper describes the development and applications of a heat transfer model, as well as the flow through the dissociated zone by leak-off from the fracture. The analytical solution, obtained through the introduction of some simplifying assumptions, has two main advantages: it can be used without any digital computing equipment and can be easily handled by field engineers.

Graphical results indicate that with S.T.S.F. method gas production and the energy efficiency ratio are three times as high as with any method.

The paper ends with an attempt to analyse the economics of natural gas production from gas hydrates, assuming a satisfactory method of hydrates recovery.
Integration of Cement Job Data for Better Bond Index Interpretation
Authors: Jutten J. , Toma I. , Morel Y. , Ferreol B.
Published: December 2007

Cement job evaluation has always been a major problem. Acoustic and ultrasonic logs are widely used to assess the quality of the cement job but even experts experience difficulties in locating cement on a bond log.

Bond Index (BI) has been the only interpretation method to make quantitative evaluation of the cement job. Un-fortunately, BI is far from being an exact figure and in many cases it will not be a valid method to use. Moreover, whenever BI is valid, it is very difficult at present to choose the right references for doing the interpretation. This paper demonstrates that the evaluation of cement jobs can be significantly improved when the design and actual cement job data are taken into consideration. Integration of this data, linked to characterizing the cement by its acoustic properties rather than its compressive strength, allows a calculation of all reference values for a better BI interpretation, and prevents misinterpretation in many cases. Field cases are also discussed which show the validity and the added benefits of the new integrated approach.1
A Comparison of Beam and Submersible Pumps in Small Cased Wells
Authors: Butlin D. M.
Published: December 2007

Using capital and power cost as measures, a comparison is made of the two most popular forms of artificial lift: beam pumps and submersible pumps. After discussing the difficulties involved, and simplifications required in making the comparison, limits of operation are established and a common range of depths and rates suitable for both techniques is found. Within this range many sets of equipment are sized, using computerized selection programs, and capital and power costs are calculated. The results are compared and a total ‘10 year cost’ is estimated for each unit. Capital costs are found to be higher for beam pumps, but power consumption is less. Charts summarize the findings for easy reference.
Performing Workover Drilling Operations Through Small-Diameter Restrictions
Authors: Fultz J. D. , Pittard F. J.
Published: December 2007

In the effort to reduce costs, many companies are investigating the cost effectiveness of completing some types of workover operations without removing the production tubing. These operations include scale removal, frac sand removal, squeeze-reperfing, underrearning and junk/fish removal. All of these operations are currently feasible using either slimhole work strings or coiled tubing in conjunction with slimhole PDM's. This paper describes the tools and procedures used to complete these operations and compares their cost effectiveness with conventional operations. A section is included on new tools being developed which should broaden the scope of these operations. The paper concludes that slimhole workover drilling operations can provide sub-stantial economic benefits compared to conventional workover methods.
Cathodic Protection Maintenance/Monitoring on Oilfield Well Casings
Authors: Garg Arvind K. , Wegener Delano P.
Published: December 2007

This paper describes a new software program developed for the maintenance/monitoring of cathodic protection systems on oilfield well casings. The program was a joint effort by Mobil E&P U.S. and EMDT.

Due to Mobil's large number of cathodically protected wellbores in Oklahoma, a suitable computer program for monitoring well casings was necessary. Although many computer programs have been developed for the monitoring of cathodically protected pipelines, these programs did not satisfy the well casing need because of differences in systems.

The software program developed satisfies all the reading requirements for the corrosion engineer, yet is simple enough for everyday use by field personnel. In addition, due to a large geographical area, an adequate means of data transmission also had to be established so that appropriate control could be maintained from a central location.
Two-Phase Flow Correlations as Applied to Pumping Well Testing
Authors: Kabir C. S. , Hasan A. R.
Published: December 2007

In a pumping-well buildup test, computation of bottomhole pressure (BHP) and flow rate (BHF) requires the use of a two-phase flow correlation for estimating the gas void-fraction or holdup along the pipe length and shut-in time. Various correlations are available to perform this task.

The purpose of this work is to review these two-phase correlations and to provide an objective evaluation. This analysis is necessitated by the fact that considerable differences in BHP and BHF may occur-depending upon the correlation used-in wells with long pumping liquid columns or those that have high gas/liquid ratio production. Consequently, a potential exists for obtaining different reservoir parameters from transient interpretation.

Using laboratory data for two-phase flow in annular geometry, relative strengths of these correlations are explored. Our own data and those of others (a total of 114 points) are used in this comparative study. For static liquid columns, the correlations of Hasan-Kabir, Gilbert, and Podio et al. provide acceptable agreement with experimental data, exceptions being the Godbey-Dimon and Schmidt et al. correlations. In contrast, for the moving liquid column scenario, as in a buildup test, the Hasan-Kabir model provides the best agreement with the dataset used in this work. A basis for smoothing the bubbly/slug transition boundary is given for the Hasan-Kabir method, together with a field example.
Selection of High-Alloy Tubulars for the 823 Field (Mobile Bay)
Authors: Wilhelm S. M. , Currie D. M.
Published: December 2007

The paper provides laboratory test data that was used to select high strength, nickel base alloy, production tubing for Mobil's 823 field. The application is of critical importance because of the large quantity of H2S (0.5 to 5 mole percent at 20,000 psi BHP) present in Mobile Bay wells. A rigorous test and evaluation program was required to ensure that the selected tubulars are immune to stress corrosion cracking and localized corrosion. New test methods consisting of slow strain rate experiments and critical pitting temperature tests were employed to diagnose temperature limitations and alloy class suitability.

The data suggest that some alloy types may exhibit an localized corrosion and stress corrosion cracking at intermediate temperatures (250 – 350 F). The intermediate region of temperature in which cracking is seen for cold worked high alloy tubing is a novel observation for sour gas well environments and is associated with situations in which the normally protective chromium oxide on the metal is transformed to a predominantly sulfide film. Elemental sulfur was found to have a major influence on cracking susceptibility.

This research supports the economic selection of high alloy tubing for critical applications such that the alloy content is matched to the actual field requirements this resulting in significant cost savings. Reliability of production equipment is maximized by a firm understanding of degradation mechanisms and temperatures.
Effect of Sidewell Completion on Steamflood Performance of Inverted Nine-Spot Patterns
Authors: Hong K. C. , Ziegler V. M. , Peacock S. M.
Published: December 2007

A numerical simulation study was undertaken to determine the best completion scheme for the sidewell in an inverted nine-spot pattern. Simulation results showed that completing the sidewell across the bottom 20% (1/5) of the target interval produces the largest cumulative oil at the lowest cumulative steam-oil ratio. This completion scheme was found to be best regardless of the pattern size (2.5 or 5.0 acres) and the initial reservoir temperature (90 or 200°F).

If an intermediate shale lense is present in the sand, the oil additionally recovered by partially completing the sidewell over that by fully completing it decreases with a decrease in vertical permeability of the shale lense. This results because the effects of steam override and gravity drainage diminish with decreasing vertical permeability.
Environmental and Permitting Considerations for Causeways Along the Beaufort Sea, Alaska
Authors: Robertson S. B.
Published: December 2007

One of the environmental constraints on oil and gas development on the North Slope of Alaska has to do with the need for causeways. Causeways have been used to support docking facilities, drilling and production facilities, and waterflood sea water treatment plants. The design preferred by industry is a solid-fill, gravel causeway. Many governmental permitting and resource agencies feel that the environmental effects of this design are unacceptable. Two solidfill gravel causeways have been built in the vicinity of Prudhoe Bay. It has been found that some alteration to circulation patterns and localized, temporary changes in nearshore fish habitat results from the presence of these structures. While some fear that this puts the fish populations at serious risk, no effects on the local fish population have been found. Nevertheless, other, more expensive and technically unproven (in Arctic) options, such as subsea pipelines and bridge type structures, have been proposed, as environmentally preferred alternatives. These should be site specific decisions. The increased difficulty in obtaining permits for gravel causeways may result in not being able to develop some nearshore reservoirs.
Risk-Weighted Optimization for Cyclic Steam Stimulation of Water-Underlain Reservoirs
Authors: Mehra R. K. , Ding L. Y. , Donnelly J. K.
Published: December 2007

The paper describes the procedure that was adopted to develop operating guidelines for the cyclic steam stimulation process in a water underlain oil sands reservoir. The study consisted of three parts: i) The risks associated with fracturing into water sands were quantified by conducting a stochastic simulation; ii) Numerical simulations were conducted to obtain correlations among the cumulative production volumes and six selected operating variables; iii) These correlations were subsequently embodied in the economic model to maximize the profits under different constraints.

The study concluded that rather than a unique value, a wide range of operating conditions maximized the project profitability. It recommended that a cautious approach in exploitation of these resources was warranted since the penalty for selecting non-optimal conditions was not high.
Effect of Ranking Criteria on Development Goals in Capital and Manpower-Limited Oil and Gas Organizations
Authors: Starzer M. R.
Published: December 2007

This paper summarizes a study to determine the effect of financial ranking criteria on development goals of oil and gas organizations. Economic analysis and ranking was applied to one hundred projects representing oil and gas investment opportunities available to an organization. Each project's after tax cash flows were subjected to four financial analysis methods for ranking. The four analysis methods used were net present value to investment ratio (NPVI), internal rate of return (IRR), payback period and profit to investment ratio (P/I). After ranking, the projects were totaled according to a particular organizational objective. Totaling of projects by ranking would continue until a limiting resource to the organization was exhausted.

This study demonstrates the insensitivity of financial analysis methods for ranking whether the organization is limited by capital or manpower. It concludes that the only requirement for a ranking criterion to properly allocate resources is that the criterion quantifies the organizational goal to some degree. Decision makers charged with selecting the most attractive growth portfolio of investment opportunities will do well with any profit measuring criterion for ranking.