bluuebunny/crossref_metadata_2025 huggingface dataset:
Capillary Number Relations for Some North Sea Reservoir Sandstones
Authors: Garnes J. M. , Mathisen A. M. , Scheie A. , Skauge A.
Published: December 2007

The paper summarizes measurements of capillary desaturation curves for some North Sea sandstone reservoirs, which are candidates for enhanced oil recovery processes. The capillary number, Nc, is altered both by increase of the viscous forces and by reduction of the capillary forces (lowering of interfacial tension). The capillary desaturation curves, CDC, are compared to the pore size distribution, XRD, liquid permeability, and dispersion coefficient, measured on the same core material. The critical capillary number and the shape of the CDC are interpreted by dispersion/capacitance effects, pore size distribution and wettability, and are found to correlate to both the dispersivity and the permeability of the cores.

Cores drilled with oil based mud showed only minor change in oil saturation, when the capillary number were increased. While cores drilled with water based mud gave a normal decrease in oil saturation at high Nc. After applying a multi-step cleaning procedure, the CDC was in agreement with results from water based cores from the same formation. The capillary desaturation data is compared to results of sandstones from other areas, showing that some North Sea sandstones are good candidates for enhanced oil recovery processes based on lowering of the interfacial tensions.
A Flue Gas Huff ‘n’ Puff Process for Oil Recovery From Shallow Formations
Authors: Johnson H. R. , Schmidt L. D. , Thrash L. D.
Published: December 2007

Troutman Oil Co., Inc. of LaCygne, Kansas has developed a low-cost process for recovery of oil from shallow oil formations. The process (named "TWINC02") relies on immiscible displacement of oil through the injection of flue gas in a cyclic injection program. It was first installed in the LaCygne-Cadmus field located in Linn County, Kansas. The project has been in continuous use since 1979. Oil production rates have stabilized and the project has proven to be cost-effective given its small investment requirements and low operating costs.

Flue gas is generated by burning natural gas in an internal combustion engine. The exhaust gas is treated and is compressed to around 250 psi for injection into the reservoir. Following injection, the same well is converted to production and the well flows oil, water, and gas into surface separating units.

The economics associated with this oil recovery process as reported in the paper have been updated to reflect 1989 prices and conditions.

This analysis assumes that the oil producing wells and related oil production infrastructure are in place. The analyzed project area contained 51 wells in 225 acres. Incremental cost to install a system in 1989 similar in scale to that employed by Troutman Oil is estimated to be approximately $100,000. For the Troutman Oil scale of operations, the operating costs are estimated at $37,400 per year.

Cash flow and profitability depend on the level of oil production, posted prices, and net revenue interest in a lease. For example, at a posted price of $20 per barrel and average oil production of 15 barrels per day, the annual cash flow from the entire project is estimated at $43,000 assuming an 80 percent net revenue interest. This level of cash flow will payback the initial investment in 2.3 years (undiscounted) and yields an internal rate of return of 42 percent over a 10 year project life. Economic parameters are presented in this report which will enable the reader to estimate the economics associated with application of the process at a particular property, including the minimum oil production required to cover operating costs and repay the initial capital investment.
Waterflooding the Minnelusa With Aluminum Citrate Gelled Polymer, Powder River Basin, Wyoming
Authors: King W. A.
Published: December 2007

Because of their high permeability variation and high viscosity ratio, Minnelusa formation waterfloods have been polymer/flooded for many years. The application has been documented numerous times.

To increase polymer viscosity insitu, alternate injections of aluminum citrate and polymer were begun in the mid 1970's. The results were difficult to document and the probability of efficient insitu mixing and, therefore, efficient insitu gellation was questioned.

The problem of efficient mixing was solved in the mid-1980's when aluminum citrate was mixed with polymer on the surface just prior to injection. Gellation would occur underground. The continuous surface mixing of polymer with aluminum citrate has become standard practice in the Powder River Basins Minnelusa waterfloods.
Use of Computer Graphics in Large-Scale Reservoir Simulation
Authors: Huang A. Y. , Ziauddin Z.
Published: December 2007

Development of a reservoir simulation model involves collection and analysis of an enormous amount of reservoir and well data for initial input. Computer graphics is the most effective tool for geologists and engineers to visualize, verify, and analyze the input data. After each simulation run, simulation engineers then have to depend heavily on computer graphics to analyze an even more intimidating amount of simulation results data. This is especially true at Saudi Aramco because of the large simulation models used to simulate the world's largest hydrocarbon reservoirs.

Saudi Aramco's EXPEC Computer Center supports a wide spectrum of computer graphics applications to aid the exploration and engineering staffs through the entire cycle of reservoir characterization. The graphics applications help during the pre-simulation model data analysis as well as in the post-simulation results analysis.

Larger and more accurate simulation models are currently being developed In Saudi Aramco. Computer technology (both software and hardware) needs to advance continually such that computer graphics can be utilized as an effective and efficient engineering tool by reservoir simulation professionals.

This paper addresses Saudi Aramco's experience in dealing with very large simulation models and using computer graphics as an engineering tool. The program efficiency, device dependence, and data management problems will be discussed. The computer speed, data storage and access methods, data transmission speed, and graphics devices will also be detailed.
Criteria for Professional Engineering Microcomputer Software Human Interfaces
Authors: McCreary J. G.
Published: December 2007

To be fully effective, engineering software must be easy to learn and easy to use for the casual first time user, as well as powerful enough to satisfy the experienced power user. The "human interface" represents how the user and the software communicate via keyboard, mouse, digitizer, screen, plotter, and printer. Better human interfaces make the software less mysterious and easier to use and improve the quality of the output but at the cost of more programming time.

The term "user friendly" is much over used without ever being defined. The more recent term "robust" has not provided better definition. Every individual or organization has at least a subconscious definition of these terms and has formed an opinion of the minimum acceptable level of software human interface. Whether developing or buying software, it is necessary to establish firm criteria of exactly what is the minimum acceptable. In addition, thought must be directed toward the optimum human interface balancing features that are "nice to have" against development cost.

This paper suggests a reasonable balance between the hypothetical ultimate human interface and the cost of development.
Coiled Tubing Workovers in Deep, Hot Wells
Authors: Mirza T. , Budiman M. , Cannan W. L. , Bordelon T. P.
Published: December 2007

Mobil Oil Indonesia Inc. has successfully utilized a 1-1/2" OD coiled tubing unit in a well workover to isolate the upper portion of the producing zone. This isolation is necessary to produce gas, richer in condensate, from the lower producing zone. It was proved that the coiled tubing unit was able to perform squeeze cementing and drilling out of same at a depth of 10,000 ft and bottom hole temperature (BHT) of 350 °F.

Ottawa sand was pumped to temporarily block the lower zone. A 3-3/8" down hole drilling motor with a 4-1/2" flat bottom mill was used to drill out cement.

The cost of the workover using the coiled tubing unit was approximately US $ 400,000. Had a conventional drilling or workover rig been used, the workover cost would have been significantly higher. Furthermore, this operation requires less well shut down time as the wellhead and flowlines do not need to be dismantled for the workover.

One Arun Field gas well has been worked over with this technique. Before the workover, the well produced with a condensate to gas ratio (CGR) of 34 bbl/MMSCF. Post workover results indicate that the well is currently producing with a CGR of 60 bbl/MMSCF.

There were some problems in the first job associated with the high temperature of the reservoir. These problems have been overcome which will result in lower workover costs on subsequent jobs.
The Effect of Surface and Downhole Boundary Conditions on the Vibration of Drillstrings
Authors: Clayer F. , Vandiver J. K. , Lee H. Y.
Published: December 2007

Surface and downhole boundary conditions are identified for a typical drill string using a 17.5 inch tri-cone bit. A case study is presented using surface vibration data acquired in production drilling operations in southern France. The data presented include high bandwidth force, torque and acceleration measurements, made on the surface with an instrumented sub. The sub was inserted in the drill string just below the power swivel The results include direct impedance measurements of the drilling rig in torsional and axial motion. Comparisons are made between simulated and measured impedance functions. The results also include estimates of the boundary condition at the bit in torsional and axial motion. Surface measurements are compared to simulated transfer function models of the entire drill string for torsional and axial vibration. A relative displacement source is introduced as a realistic model of the action of a tri-cone bit.
Materials Assessment for Sour Service Applications
Authors: Kermani M. B. , MacCuish R. G.
Published: December 2007

In detecting the susceptibility of tubular goods to sulphide stress cracking (SSC), a novel, easy and reproducible approach has been established, offering prediction of long term exposure behaviour. Two techniques have been used to evaluate the SSC behaviour of materials by placing the emphasis on FAILURE PREDICTION. These include constant extension rate tensile (CERT) testing and the use of a fracture mechanics approach. The former method provides an efficient and rapid method of ranking of materials based on normalised strain to failure. The latter has been employed to identify threshold stress intensity factor (KIscc) below which the material can be used safely and confidently. The approach adopted incorporates both techniques combining the ease of CERT testing with the accuracy of fracture mechanics, on the basis of which fitness for purpose evaluation of tubular goods have been carried out.

The results have led to a better definition of operational limits of tubular goods for sour service applications over a wide range of testing conditions. This has enabled the selection of the most suitable/cost effective material for specific use. The environmental variables studied include solution chemistry, the pH, testing temperature and hydrogen sulphide partial pressure.
A Study to Determine the Effect of Damping on Finite-Element-Based, Forced-Frequency-Response Models for Bottomhole Assembly Vibration Analysis
Authors: Apostal M. C. , Haduch G. A. , Williams J. B.
Published: December 2007

A computer based model for avoiding and characterizing dynamically induced drill string failures is presented. This model is applicable in both a planning and a real time mode of operation. The finite element model used in this study is designed to account for the forced frequency response of a Bottom Hole Assembly (BHA) drilling in an arbitrary curved three-dimensional wellbore. As a consequence of the greater simplicity of the resulting dynamic finite element model, it is standard operating procedure in drilling mechanics to exclude the effects of damping when carrying out a forced frequency response (FFR) vibrational failure analysis of a drilling BHA. Since damping, due to the presence of fluid, formation, friction and other effects, is the real world situation, the authors undertook the work described in this paper in order to determine the nature and the magnitude of the influence which damping exerts on drilling BHA's and their associated critical failure modes.

The FFR analysis model presented herein enables a user to determine the forced frequency response (critical speeds) of a BHA due to imposed load and/or displacement excitations anywhere in the drill string. The FFR solution is computed about the displaced static configuration, which means that the Jacobian (i.e. stiffness) matrix contains the effects of contact, stress stiffening and friction. The mathematical formulation of the FFR solution algorithm has been developed in such a way as to admit damping in the steady-state response behavior. An important implication of damping is that while the response of the BHA will be at the same frequency as the excitation, it need not be in phase with it. A major benefit of this model is that it provides a mechanism to evaluate the effect of including (or neglecting) damping in conventional BHA FFR finite element analysis.

With regard to the above described study, this paper first reviews the theoretical basis for the FFR model utilized and follows with a presentation of field data case studies. These studies validate the utility of employing the model to predict (and therefore avoid) critical rotating speeds and also demonstrate the significant role which damping plays in obtaining useful real world results from FFR finite element analysis. In this regard, the effects of both uniform and frequency dependent damping upon critical operating speed ranges and response magnitudes are examined.
Openhole Drilling Using Coiled Tubing and a Positive Displacement Mud Motor
Authors: Fultz J. D. , Pittard F. J.
Published: December 2007

An investigation into the feasibility of drilling openhole with coiled tubing indicates that such operations are feasible using currently-avaliable technology. The study covers aspects of the drilling operation, including bottomhole equipment, surface equipment, coiled tubing unit, drilling logistics and cost. The conclusion is made that coiled tubing drilling operations can provide benefits in terms of safety, formation damage and economics.
Education and Professionalism for the 90's
Authors: Curtis L. B
Published: December 2007

Engineering education, and the professionals it produces, will continue to be subject to many changes and pressures through the 1990's. Their performance will be viewed from the perspectives of society and the many institutions that function within its framework. Technology will continue to change in the petroleum industry in response to its needs, and the pressures placed on it from other quarters.
Use of a Multifractal Approach for Multiphase Flow in Heterogeneous Porous Media: Comparison with CT-Scanning Experiment
Authors: Lenormand R. , Kalaydjian F. , Bieber M-T. , Lombard J-M.
Published: December 2007

This paper depicts an original model for the description of heterogeneous media, based on fractal and multifractal geometries.

Rather than using, as in Hewett's fractal approach, a random noise to generate heterogeneous patterns, we have developed an approach much closer to geostatistics and based on multifractal approach. Multifractal is a characterization of spatial distribution of a continuous variable, such as permeability or porosity. The construction rule is based on a multiplicative process which gives a multifractal square structure with the size 2n × 2n. The main property of such a construction is the correlations it gives at all length scales.

This method is then modified to generate anisotropies in the x and y directions by using rectangular rather than square multifractal blocks.

A wide variety of patterns is obtained by tuning only two dimensionless correlation lengths. Consequently, any pattern can be located on a 2D diagram with the extreme cases being the homogeneous medium, the horizontal and vertical layering, and the multifractal.

Two-phase displacement patterns are obtained by a network flow simulator coupled to this anisotropic multifractal generator. The results are in good agreement with experimental patterns obtained by CT-Scanning during gas injection in layered Berea sandstone.

The model contains the main features of the rock sample, which play a role in immiscible displacements, such as randomness, all ranges of correlations and anisotropy.
Microbial Enhanced Oil Recovery: Interfacial Tension and Gas-Induced Relative Permeability Effects
Authors: Chisholm J. L. , Kashikar S. V. , Knapp R. M. , Mclnerney M. J. , Menzie D. E. , Silfanus N. J.
Published: December 2007

Potential mechanisms involved in microbial enhanced oil recovery (MEOR) from sandstone reservoirs are reviewed. Three phase relative permeability studies have shown that residual oil saturation can be reduced by the presence of gas in a water wet system. The production of biogenic gas to create a free gas phase can account for incremental oil recovery in MEOR processes.

Reduction in interfacial tension between formation fluids can be caused by metabolic products. Also, bacterial plugging appears to preferentially occur in larger, high permeability pores. As this occurs fluid is diverted into smaller pores causing an increase in fluid velocity within them. The changes in interfacial tension and fluid velocity combine to increase capillary number. Increases in capillary number are associated with reduction of residual oil saturation.

Core experiments are related to the results of these studies. The methods discussed can partially account for additional oil recovery in an MEOR process.
Coping with Change: Preparing for Survival and Growth—The Human Resources View
Authors: Frantz L.
Published: December 2007

I appreciate the chance to come and talk with you today. I began my career with Phillips Petroleum in the mid-1960s with a civil engineering degree.

Through a variety of jobs in West Texas, then the waters of Norway, I learned about the nuts and bolts of the oil business. Then Phillips asked me to take a new job ... that of vice president of human resources. A whole new kind of science was laid before me ... the science of the workforce.

It's been a real education ... and a sobering one, too, because I have learned that some big challenges lie ahead of us in the human resources in our companies. Now, I know that you may not want to hear that. Everyone here knows how tough the '80s were for the petroleum industry, especially in the engineering and research departments of the petroleum industry. I honestly don't expect the '90s to be any less turbulent but they can be more fruitful if our industry puts more muscle into the hard sciences. We need to do it now ... because we are living on borrowed time.

Maybe you read the report put out last year by the Geoscience Institute for Oil and Gas Recovery. The report said proved reserves in the lower 48 states peaked in 1961! And production peaked in 1970, except for a short-lived spike in the early 1980s when prices were much higher than they are today. The reason our energy situation isn't worse today is technology. Our strong research and engineering experience helped us pull more oil from our aging fields.

But while our engineering expertise helped us develop oilfields, we neglected another valuable resource ... people.

We are about to pay for that neglect because the petroleum industry is facing a shortage of a valuable natural resource:New employees with training in the hard sciences — the very lifeblood of our industry.
Wettability Evaluation During Restored-State Core Analysis
Authors: Hirasaki G. J. , Rohan J. A. , Dubey S. T. , Niko H.
Published: December 2007

Wettability changes during stages of restored state core analysis were evaluated for a North Sea reservoir. The goal was to determine the proper technique for estimating the remaining oil saturation after waterflooding from core analysis.

The traditional methods for quantifying wettability, i.e., USBM and Amott indices and the Brownell-Katz correlation, were evaluated. It was found that the USBM and Amott procedures, when modified slightly, could be interpreted to give a good indication of wettability.

The traditional method of cleaning cores by Dean-Stark extraction with toluene followed by chloroform/methanol was found to be ineffective in making a core water-wet. To overcome this difficulty, we evaluated core cleaning procedures that employ a sequence of solvents. The remaining oil saturation increased from 9% with crude oil in the "as received" state to 28% with refined oil after the third cleaning.

Once the cores were made water-wet, aging the cores in a North Sea crude oil returned them to a mixed-wet state. However, the restored state cores were not as oil-wet as the "as received" state cores. Even after aging, there was a significant difference between the cores cleaned by Dean-Stark extraction and by a sequence of solvents. The mixed-wet condition with the North Sea crude oil is, therefore, expected to apply to the field: the crude oil base number, isoelectric point, effluent pH during core floods, and bottle wettability tests support this contention.

Examination of the Brownell-Katz number correlation and the capillary pressure curves showed that much of the remaining oil saturation in a mixed-wet core, during core analysis could be due to retention by a capillary end effect. This was supported by a CT scan of the core. In this mixed-wet reservoir, the remaining oil saturation is not equal to the residual oil saturation, but must be calculated using the appropriate relative permeability curve and the effect of buoyancy.
An Integral Equation Formulation for Two-Phase Flow and Other Nonlinear Flow Problems Through Porous Media
Authors: Chen Zhongxiang , Bodvarsson G. S. , Witherspoon P. A.
Published: December 2007

Many flow problems encountered in petroleum reservoir engineering are characterized by nonlinearities and are difficult to solve analytically. The concept of a relative mass flow rate function is used to arrive at an integral equation formulation for some of these nonlinear flow problems. This formulation has some distinct advantages over existing methods of handling such nonlinear flow problems because of its generality and simplicity.

The problems considered include two-phase fluid displacement including the effect of capillary pressure and isothermal transient flow of gas. These problems can be described by nonlinear parabolic partial differential equations that have self-similar solutions.

Exact semi-analytical solutions are obtained which can be easily evaluated using a rapidly-converging iteration process. A new understanding of the mechanism of the displacement of a non-wetting phase by a wetting phase has been developed that is dependent on a critical value of the dimensionless injection rate constant.
Ultrasonic Measurements of the Bubble Nucleation Rate During Depletion Experiments in a Rock Sample
Authors: Hoyos M. , Moulu J-C. , Deflandre F. , Lenormand R.
Published: December 2007

By means of an ultrasonic technique, the nucleation rate J in depletion experiments has been measured. An array of 8 ultrasonic transducers, fixed along a rock sample, continuously scans the sound velocity and the attenuation in the sample. Due to the great difference in sound velocity between the gas and the liquid, bubbles are easily detected and located by transducers. The sample is also set up with capillary tube at one end for the observation of production by the displacement of a meniscus. The main advantage of ultrasonic technique is the capacity to work at high pressure and temperature. An improvement in the accuracy over the standard techniques is observed.
Analysis of 15 Years of Thermal Laboratory Data: Relative Permeability and Saturation Endpoint Correlations for Heavy Oils
Authors: Frizzell D. F.
Published: December 2007

Fifteen years of laboratory high temperature relative permeability and endpoint saturation data are analyzed. Equations are given for estimating the irreducible water and residual oil saturation to water, gas and steam based on temperature, crude oil API gravity, and absolute permeability to water. Other equations provide estimates of the permeability endpoints. These equations are applicable for heavy oils in the gravity range of 7° to 20° API, the temperature range of 75° to 400°F, and for unconsolidated sands. The calculated estimates should serve as initial input for reservoir computations; they do not substitute for measured laboratory data.
Laminated Sands: An Assessment of Log Interpretation Accuracy by an Oil-Base Mud Coring Program
Authors: Dawe B. A. , Murdock D. M.
Published: December 2007

An assessment of log interpretation accuracy in laminated sand/shale intervals of selected Malay basin formations has shown excellent overall agreement to core derived standards of hydrocarbon pore volume. In the reservoirs studied the log interpretation indicated 4.7% less original oil-in-place overall. Log calculated hydrocarbon pore volume ranged from +2 to −18% of the core derived values in individual reservoirs.

Accurate and precise standards of hydrocarbon pore volume were derived from a coring program that required the development of an oil-base mud system, closely monitored drilling and coring operations, totally integrated logistics and pertinent core testing procedures. Extensive quality control measures comprising mud system monitoring by interfacial tension measurements, chemical tracing of the mud system, invasion studies by core layering tests and core analysis procedures were implemented to validate the core data.

Representative core porosity and saturation data were weighted to emulate logging tool response. The simulated log responses were compared to actual log responses to identify and quantify intervals of difference.
Spin Echo Magnetic Resonance Logging: Porosity and Free Fluid index Determination
Authors: Miller M. N. , Paltiel Z. , Gillen M. E. , Granot J. , Bouton J. C.
Published: December 2007

The paper describes the first spin echo Magnetic Resonance Imaging Logging (MRIL*) system. The system makes measurements while logging and does not require special borehole treatment. The tool employs static and radio-frequency magnetic fields to perform downhole the spin-echo magnetic resonance measurements with short "dead time" that previously have been possible only in the laboratory.

Logs of lithology independent porosity, irreducible water saturation and fluid diffusion coefficient are provided from real-time analysis of the spin-spin relaxation time (To) decay of the fluids contained within the pore space of the formation. Spin-lattice relaxation time (T1) behavior is directly measured by the MRIL system.

Engineering prototypes have undergone several field tests, including two tests at the Conoco Borehole Test Facility well in Newkirk, Oklahoma. Field data, including the demonstration of accuracy and repeatability are discussed. The magnetic resonance logs correlate well with measurements of porosity and irreducible water saturation made on core samples and with porosity data from standard density and neutron logging tools.

Such data, from magnetic resonance logs, can be applied to the determination of porosity and irreducible water saturation, and thus to the estimation of permeability.
A Comprehensive Study of Pressure Transient Analysis with Sorption Phenomena for Single-Phase Gas Flow in Coal Seams
Authors: Anbarci K. , Ertekin T.
Published: December 2007

This paper identifies the need for the development of specialized solutions for pressure transient analysis in coal seams and, subsequently, provides a comprehensive solution package for these reservoirs. The proposed solutions are applicable to radial systems with finite wellbore radius and with either an infinite outer boundary, a constant pressure outer boundary or a closed outer boundary. At the inner boundary constant pressure or constant terminal rate cases can be specified.

The single-phase flow formulation for coalbed methane includes non-equilibrium sorption phenomena in the coal matrix and laminar gas transport in the natural fracture network (cleat system). The transport of methane in the coal matrix is described by using spherical elements. The mathematical models which account for unsteady state and pseudosteady state matrix/fissure methane transfer are incorporated to the transport equation.

In order to obtain a closed form solution in real time domain and avoid the pitfalls of numerical inversion approximate inversions of the solutions from the Laplacian space are also developed. These closed form solutions are found to be in good agreement with the numerically inverted solutions. The effects of different models of matrix/fissure flow on the solution are also discussed. The validity of the proposed analytical solutions are checked against a numerical simulator and comparisons showing good agreements between the two are presented.

The solution package describes forward solutions which have the potential to be used in an interpretation method for in-situ characterization of coal seams and other gas reservoirs where adsorption and desorption phenomena are considered to be active.
Horizontal Well Test Analysis System
Authors: Suzuki K. , Nanba T.
Published: December 2007

In this paper, rigorous automated horizontal well test analysis system is presented to obtain vertical and horizontal permeabilities, and skin factor for single phase and primary porosity reservoirs, which system is applicable in both constant and variable rate cases.

Although a plenty of papers on transient behaviour of horizontal wells have been published, the following two important aspects in terms of real pressure data analysis have rarely beentouched.

Firstly, most of the existing methods are based on the assumption that production rate isconstant. However, this assumption is rarely acceptable, especially for the reservoirs with low vertical/horizontal permeability ratio (KV/KH) where production rate usuallydecreases rapidly. Secondly, the early-time data, which is critical to estimate KV/KH are often masked by the wellbore storage effect.

The developed analysis system overcomes the difficulties mentioned above by using a robust nonlinear regression algorithm. Some examples including real field data are presented in this paper.
The Use of Modern On-Site Bioremediation Systems To Reduce Crude Oil Contamination on Oilfield Properties
Authors: Hildebrandt W. W. , Wilson S. B.
Published: December 2007

Oilfield properties frequently have areas in which the soil has been degraded with crude oil. Soil contaminated in this manner is often considered either a hazardous waste or designated waste under regulatory guidelines. As a result, there is often concern about an owner's liabilities and the financial institution's liabilities whenever oilfield properties are transferred to new operators, abandoned, or converted to other uses such as real estate. There is also concern about the methods and relative costs to remediate soil which has been contaminated with crude oil.

Modern, well-designed, soil bioremediation systems are cost-effective for the treatment of crude oil contamination, and these systems can eliminate an owner's subsequent liabilities. Compared to traditional landfarming practices, a modern on-site bioremediation system (a) requires significantly less surface area, (b) results in lower operating costs, and (c) provides more expeditious results. Compared to excavation and off-site disposal of the contaminated soil, on-site bioremediation will eliminate subsequent liabilities and is typically more cost-effective.

Case studies indicate that on-site bioremediation systems have been successful at reducing the crude oil contamination in soil to levels which are acceptable to regulatory agencies in less than 10 weeks. Totals costs for on-site bioremediation has ranged from $35 to $40 per cubic yard of treated soil, including excavation.
Laboratory/Field Study of Oil-Soluble Resin-Diverting Agents in Prudhoe Bay, Alaska, Acidizing Operations
Authors: Strassner J. E. , Townsend M. A. , Tucker H. E.
Published: December 2007

Treatment of long intervals of varying permeabilities and thief zones requires fluid diversion control to assure well distributed fluid placement. Oil Soluble Resins (OSR) , when properIy appl i ed, ar e effective, readily removable diverting agents. Application of laboratory studies of 15 OSR products from 5 service companies combined with additional OSR field experiments at Prudhoe Bay ( PB) , br ought about the use of higher concentrations and larger size OSR particles and resulted in improved diversion during acid stimulation and scale inhibitor squeeze treatments. Successful OSR field applications depend both on selecting proper OSR particle size distributi ons and sufficient OSR concentrations for rapid bridging on pores and/or fractures being contacted. Tests of sand/gravel packs, confirmed that effective sealing was achieved when the median OSR size was equal to or greater than 1/3 of the calculated mean sand pore diameter. With fractured cor es, however, effective seal i ng by OSR concentrations up to 10 wt% required that 1020% of the OSR particles be as large or slightly larger than the fracture width. Smaller volumes of higher OSR concentrations were more effective in diversion than larger volumes of lower concentrations. Generally, a broad particle size distribution was desirable for sealing fractures whereas fine particle sizes were better for 350 md to 3500 md sandstone cores.
A Comprehensive Mechanistic Model for Upward Two-Phase Flow in Wellbores
Authors: Ansari A. M. , Sylvester N. D. , Shoham O. , Brill J. P.
Published: December 2007

A comprehensive model is formulated to predict the flow behavior for upward two-phase flow. The comprehensive model is composed of a model for flow pattern prediction and a set of independent models for predicting the flow characteristics such as holdup and pressure drop in bubble, slug and annular flows.

The comprehensive model is evaluated by using a well databank that is composed of 1775 well cases covering a wide variety of field data. The performance of the model is also compared with the six commonly used empirical correlations.

The overall performance of the model is in good agreement with the data. In comparison with the empirical correlations, the comprehensive model performs the best, with the least average error and the smallest scattering of the results.
Casing Crush Resistance Loss to High-Density Perforating: Casing Tests
Authors: King G. E.
Published: December 2007

The tests on crush resistance loss in casing following high density perforating has been expanded from the model study of SPE 18843 to include several perforated casing samples. The test set now includes high density, very large hole perforations in 9-5/8" and spiral and planar, high density patterns in var-ious casing sizes. The effect of hole size and location have now been separated from the effects of the explosion of the charge. Samples of full size, perforated casing have been compared for crush resistance to companion samples of casing drilled with the same size and pattern of holes.
New, Generalized Criteria for Determining the Level of Underbalance for Obtaining Clean Perforations
Authors: Tariq S. M.
Published: December 2007

New criteria for estimating underbalance requirements for obtaining clean perforations are presented. These criteria are based on analysis of flow velocities and pressure gradients in the near wellbore region at early times using finite element method, existing field data and a physical model of perforation cleanup. The results indicate that the required level of underbalance is one that will introduce non-Darcy effects in the vicinity of perforations at early times. Simple equations based on pseudosteady-state, radial and turbulent flow in the crushed zone have been presented to approximate the required level of underbalance for a given set of formation and fluid properties.
Automated Gas Delivery to Gas Treatment Plants Saves Flare Gas Volumes and Improves Field Operations
Authors: Fletcher B. W. , Kowalski R. A.
Published: December 2007

An automation project to control gas deliverabilities and gather production data was installed at the ARCO Oil and Gas Company's Empire Abo Unit located just east of Artesia, New Mexico. The unit has 383 wells and produces approximately 4000 BOPD and 65 MMCFD. Eleven satellite batteries throughout the unit handle the unit's liquid and gas production. Each satellite delivers gas to two different gas plants operating in the area. Due to the New Mexico state gas production regulations, the unit is limited to a gas delivery rate of 65 MMCFD. Unit operational problems occur when either one or both of the plants require a change in gas delivery. Before the automation control was installed, field gas production was flared at the plant when plant throughput decreased. Unit operations personnel manually adjusted the gas delivery by shutting in wells. When plant throughput increased, plants were not fully loaded until additional production was put on stream. To minimize the operational problems and the amount of revenue lost to flared gas, an automation system was installed to the provide steady, maintainable gas flow to each plant under varying conditions. Automation equipment at each satellite battery measures and controls gas flow to each pipeline to a specified setpoint.

When a change in deliverability is desired by a gas plant, plant personnel enter the desired rate at a remote terminal located within the plant. That change is communicated to the central field office unit, which in turn establishes new flow setpoints and communicates the same to the individual satellite batteries remote controllers. In addition the system monitors satellite batteries operations for abnormal or alarm conditions and provides a means for notifying the operating personnel.
A Production Optimization System for Western Prudhoe Bay Field, Alaska
Authors: Barnes D. A. , Humphrey K. , Muellenberg L.
Published: December 2007

For almost a decade the Prudhoe Bay field on the North Slope of Alaska has produced at a yearly average offtake rate of 1.5 million stock tank barrels of oil per day. As the reservoir depletes and field gas-oil ratios (GORs) increase, gas handling constraints make it difficult to achieve oil rate targets. The Western Production Optimization Model (WPOM) was developed by BPX to deliver an offtake strategy that maximizes oil rate while minimizing processed gas. The model is based on the "incremental GOR" concept, or the lowest GOR selection for the next incremental barrel of produced oil.

The model is supported by a sophisticated Supervisory Control and Data Acquisition system. Data are transferred into a large relational database in BPX's Anchorage office, allowing access to current well performance data. Oil rate vs. GOR functions are generated for the ~460 BPX operated production wells. The WPOM combines well functions in an incremental manner, honoring facility limitations, to generate an optimized oil rate vs. gas rate curve. For any given gas rate, the curve defines an optimized oil rate target, which is then broken down into targets for the production facilities, flowlines, and individual production wells. The model can be updated in a matter of minutes to allow for evaluation of sensitivities or to account for changing field conditions.
Analyzing Electric Submersible Pump Failures in the East Wilmington Field of California
Authors: Upchurch E. R.
Published: December 2007

Within the Long Beach Unit of the East Wilmington Field, over 600 electric submersible pumping units (ESP's) are operated from four coastal man-made islands and one pier.

In 1984, an ESP quality control program1 was initiated which ultimately resulted in a significant reduction of ESP failures (Fig. 1). The program required (1) the use of only new rotating equipment in any ESP installation, (2) the testing of all new pumps by the manufacturer, and (3) spot testing of the pumps by an independent testing facility to ensure strict adherence to the program requirements. This quality control program continues to be the primary avenue by which an acceptable ESP run-life average is maintained in the Long Beach Unit of the East Wilmington Field. Fig. 1Recent failure history of the East Wilmington field.

The next step in reducing ESP failures in this field is to determine how the inherent conditions of each reservoir contribute to ESP failure. In so doing, the operating problems that are unique to a certain reservoir condition can be solved. Between January 1, 1985 and March 31, 1989, 1149 ESP's experienced down-hole pumping equipment failure and were subsequently replaced. This case study presents data from the 1149 failures as a function of both the reservoir properties and the pump fluid output and thereby will show the effect of each on ESP failure rates and causes.

The extensive number of low volume ESP's utilized in the East Wilmington Field make it a superb area for the study of low volume failure mechanisms. Low volume wells are considered to be difficult to produce with an ESP primarily because of insufficient cooling of the motor. A minimum fluid velocity past the motor must be maintained to supply adequate cooling. Minimum fluid velocity recommendations, however, vary among ESP manufacturers. These recommendations range from 0.4 ft/s [0.12 m/s] to 1.0 ft/s [0.30 m/s]. A Long Beach Unit well producing 1000 bbl/D [159.0 m3/D] has a maximum fluid velocity of 0.38 ft/s [0.11 m/s] past the motor and, therefore, fits the low volume criteria. Eighty-six percent of the ESP's included in this study pumped less than 1000 bbl/D.

Although ESP's are used successfully in this field, the installations producing less than 400 bbl/D [63.6 rrr/D] do experience higher rates of failure when compared with the higher volume installations. Thirty-seven percent of the wells in this study produced less than 400 bbl/D yet their ESP installations contributed 53% of the failures.

Given the large volume of comparative data available, this study will attempt to provide insight into the causes of both low volume (<1000 bbl/D) and extremely low volume (<400 bbl/D) ESP failures in the East Wilmington Field. Changes in equipment and operational practices to increase run-life will also be examined.
Horizontal Gravel Packing Studies in a Full-Scale Model Wellbore
Authors: Forrest J. K.
Published: December 2007

abstract

Using full-scale, 45- and 100-foot models, this study shows that better methods are needed for gravel packing highly deviated (>60°) and horizontal wells. Viscous carrier fluids gave incomplete annular packing, particularly around conventional screen connections. In a few tests, better results were obtained by using low-viscosity carrier fluids such as water or a newly developed, two-stage packing technique. An equation was developed that may be used to estimate pack length limits.
Prudhoe Bay Field, Alaska, Waterflood Injection Water Quality and Remedial Treatment Study
Authors: Hsi C. D. , Strassner J. E. , Tucker H. E. , Townsend M. A.
Published: December 2007

A comprehensive laboratory and field study was conducted at Prudhoe Bay Field, Alaska to identify the cause for rapid injectivity decline and injection profile degradation in produced water injection wells and to seek remedial treatment methods to improve water injectivity. A specially designed portable core flow station was installed in the produced water treatment facility at Prudhoe Bay Field to evaluate permeability damage characteristics of produced water on reservoir core plugs and to evaluate performance of different surfactant solutions for restoring water injectivity. Test results show that Prudhoe Bay produced water caused a slow but significant permeability reduction to reservoir cores. Commercially available surfactant solutions were effective initially in restoring water injectivity when applied as slug treatments at 1 to 2% concentration levels. No surfactant solution was effective in preventing damage when injected continuously in the produced water stream at less than 50 to 100 ppm levels. Remedial acid stimulation treatments and solvent washes can restore part of the water injectivity. Study results identify the need to further improve the present produced water treatment facilities.
Growth of Bacteria on Water Injection Additives
Authors: Sunde E. , Thorstenson T. , Torsvik T.
Published: December 2007

In this study, bacteria from oil installations were used in growth experiments with 15 different chemicals normally used in injection water treatment. Growth experiments were performed using a mixture of bacteria grown under aerobic and anaerobic conditions, and SRB pure cultures grown anaerobically.

The results showed that 3 chemicals could be utilized as N-sources, 1 as P-source and 7 as C-sources for bacteria. These chemicals included 1 oxygen scavenger, 3 scale inhibitors, 1 polyelectrolyte, 1 surfactant, 2 antifoaming agents and 2 chelating agents.

The remaining 6 chemicals did not support growth under the test conditions. 5 of these, including 3 biocides, contained nutrients that may be utilized under field conditions.

From this study it is concluded that the growth potential of water treatment additives may be substansial and should therefore be investigated prior to chemical selection.
Application of Subsea Separation and Pumping to Marginal and Deepwater Field Developments
Authors: Baker A. C. , Lucas-Clements D. C.
Published: December 2007

A series of studies has been undertaken in order to quantify the benefits of various alternatives for the remote production of subsea oil reservoirs. Subsea separation and pumping appears to have significant advantages for remote production over longer distances and particularly in deep water. The concept involves the separation of gas and liquids at or near the wellhead; with the liquids being pumped in single phase back to shore, or to a remote production facility, and the separated gas flowing back to the same location under wellhead pressure.

A novel separation and pumping system has been conceived which allows an integrated separator and pump to be installed within a conventional 30" conductor in a dummy well. This novel configuration has been called VASPS (Vertical Annular Separation and Pumping System).

A detailed series of hydraulic studies has been undertaken which indicate that the system is capable of producing over distances up to 100 km and that well deliverabilities are significantly enhanced at increased water depths. We believe this to be a significant conclusion as there is an increased economic incentive to employ remote subsea production in deep water.