bluuebunny/crossref_metadata_2025 huggingface dataset:
The Leaking Liner Top
Authors: Agnew J. W. , Klein R. S.
Published: December 2007

An imperfect cement seal at the top of a liner will allow gas from below to leak into the drilling annulus above a production liner. Conversely, with a pressure differential toward the formation, fluid can be lost from the annuli during drilling or during stimulation for production. Since perfect liner cementation is an elusive target, this paper will discuss briefly the cause and effect of the leaking liner top and list the options available for solving the associated problems.

This paper was written to address the problems encountered in the drilling and completion of deep high pressure gas wells; however, much of the information can be applied to wells drilled and completed under less rigorous conditions.
Shale Production from the Britt Formation in Northwest Caddo County
Authors: Dutton K. , White J. , Johnson R. , Bemis R.
Published: December 2007

A major, and costly, problem in producing gas in the Anadarko Basin can be the production of shale. Shale production can plug surface equipment, the wellbore or cause collapse of a properly designed casing or liner. An examination of five wells that have "shaled off" in northwest Caddo County is discussed to draw some conclusion as to why shale was being produced. Each of these five wells had a production potential of at least 2 MMCFD in the Springer-Britt Sand. Production was lost and the zone had to be abandoned.

This paper examines the Britt Formation, where shale problems have been encountered. Potential solutions to cementing practices, perforation placement, stimulation techniques and production practices are outlined. Results from the five-well study are correlated and recommendations for future completions are made. These correlations and recommendations should be applicable to other geopressured reservoirs with shale production problems.
In Search of the Apache Key
Authors: Grace R. D. , Storts P. D.
Published: December 2007

In June, 1981, Apache Corporation of Minneapolis completed the Key No. 1-11 in the Upper Morrow at 16,000 feet in Eastern Wheeler County of the Texas Panhandle. The Key No. 1-11 was one of the best Morrow wells ever drilled in the Anadarko Basin having 90 feet of porosity in excess of 20 percent with an original COFP of 90 MMSCFPD. On Sunday afternoon, October 4, 1981, after being shut-in for 78 days waiting on pipeline connection, the Key No. 1-11 inexplicable erupted, blowing the wellhead, 80 feet of 2-7/8" tubing, 80 feet of 7-5/8" casing, and 12 feet of 10-3/4" casing from the well. The Key was destined to be referred to as the biggest blowout in Texas history and to become a first in many areas before it was finally killed on February 8, 1983, when the Key No. 3 relief well intercepted the 5" liner in the Key No. 1-11 blowout at 15,941 feet TVD. The expeditious intercept was made possible by extensive study and preplanning, the assistance of interested individuals within the industry, the dedication and determination of Apache management, and diligent study of all techniques used for determining the location of one well bore from another including Passive Magnetic Analysis, Ultra Long Spaced Electro Log Analysis and Active Magnetic Analysis (ELREC). This is the story of the incredible intercept, the deepest ever made in the history of the industry.
Nonacid Reactive Solution for Deep Well Stimulation
Authors: Pendergrass J. , Campbell P. , Bell D. , Bishop M. , Copeland J.
Published: December 2007

Certain formations in the Anardarko Basin have not responded well to acid-base cleanup or breakdown treatments. The use of a Nonacid Reactive Solution (NARS) for deep wells where both formation sensitivity and excessive corrosion of tubular goods present problems can produce improved well response. Laboratory analyses of the Morrow, Red Fork and Springer formations in the Anadarko Basin justify the use of NARS for stimulation treatments in these formations.

Laboratory data and production results demonstrate that NARS can be used as an economical and effective method of mud removal in wells which are drilled with oil-base mud. Further studies investigate the effect of NARS on downhole tubular goods. Well histories in the three formations support the effectiveness of the fluid, and the variety of treatment designs dictated by the diverse formation characteristics demonstrates the versatility of NARS.

By concentrating the study of rock lithologies, core and laboratory analyses, and production results, NARS can be used in breakdown and cleanup treatments more effectively than acid-base fluids in sensitive formations.
An Analytical Model for Water/Gas Miscible Displacements
Authors: Jenkins M. K.
Published: December 2007

This paper describes the solution to a steady-state analytical model for gravitational segregation in a water-alternating-gas (WAG) miscible displacement. The model, introduced by Stone (1), provides a conceptual framework for understanding the segregation process. The analysis is extended in this paper to obtain a closed-form solution to the equations, which allows one to easily estimate the incremental recovery above waterflooding for homogeneous reservoirs. This solution is useful in the design of high-recovery WAG floods. Results from the model indicate that recovery increases with dimensionless viscous-gravity ratio (VGR), which is a measure of the volume in the reservoir required to obtain complete segregation of water and gas injected into a well. The model may be used to show how changes in fluid and operating conditions affect recovery. Recovery may be increased either by increasing injection rate or solvent viscosity, or by reducing pattern area or water-solvent density difference.

The reservoir model consists of three distinct zones: a top zone in which only gas is mobile, a bottom zone in which only water is mobile, and an intermediate mixture zone in which the mobility is determined by the water-gas ratio of the injection mixture. Simple expressions are derived that define the boundaries of these zones at any location in the reservoir. These expressions are integrated to obtain ultimate recovery as a function of zone mobilities, injection water-gas ratio and viscous-gravity ratio (VGR). Recovery is shown to be a linear function of VGR for VGR less than one; for VGR greater than one, a logarithmic dependence is obtained. The same recovery expression governs both rectangular and radial geometries.

The governing equations and assumptions are discussed in this paper. The equations are solved, and example calculations are presented. Comparisons are made with numerical simulation results, and the agreement is good. The equations are examined parametrically, showing the effect on recovery of changes in water-gas ratio and zone saturations. A simplified method for using the model to estimate recoveries for VGR less than one is discussed. The method used to determine zone saturations is also described. Sufficient detail is provided to permit recovery calculations for any set of reservoir data.
Effect of Varying Polyacrylamide Molecular Weight on Tertiary Oil Recovery From Porous Media of Varying Permeability
Authors: Ball J. T. , Pitts M. J.
Published: December 2007

Three different molecular weight emulsion polyacrylamides (PAA) have been tested for their ability to recover oil from a multi-permeability Berea core system. Injection of a 6.5 × 106, 17 × 106, and 36 × 106 molecular weight PAA resulted in oil recovery from the multiple permeability core systems of 53.4, 63.7, and 57.2 percent of the waterflood residual oil, respectively. In tests with 15 g/kg Na2CO3, injection of the polymer systems resulted in recoveries of 65.6, 75.3, and 68.0 percent of the waterflood residual oil, respectively. In the presence of alkali, the injection of high molecular weight PAA resulted in the reduction of fluid flow into the medium and low permeability cores with 70 to 75 percent of the tertiary oil being recovered from the high permeability core. Decreasing the PAA molecular weight to 17 × 106 and subsequently to 6.5 × 106 resulted in an increasing amount of fluid flowing through the low and medium permeability cores. While decreasing the molecular weight of the PAA resulted in increased fluid diversion, the 6.5 × 106 molecular weight PAA recovery efficiency was less than either of the other two polymers in the high permeability core.

The data indicates selection of too large a polymer can result in less than maximum oil recovery from a heterogeneous permeability reservoir as a result of lower sweep efficiency. Selection of too small a polymer can result in less than maximum oil recovery from a heterogeneous permeability reservoir as a result of decreased oil recovery from the high permeability zones. Proper selection of polyacrylamide for a heterogeneous permeability reservoir either in the presence or in the absence of alkali will maximize oil recovery.
Quantification of Viscoelastic Effects of Polyacrylamide Solutions
Authors: Heemskerk J. , Janssen-van Rosmalen R. , Holtslag R. J. , Teeuw D.
Published: December 2007

Beyond a critical rate of flow in cores the viscoelasticity of polyacrylamide solutions is reflected by shear thickening behaviour. Practical information is provided on the critical flow rate and magnitude of shear thickening and their dependency on core permeability, temperature, molecular weight and concentration of commercial polymers. To describe the onset of shear thickening, critical Deborah numbers were calculated using fluid relaxation times obtained by oscillation rheometry. Using three core-flow parameters, viz. the critical flow rate and two power-law exponents, the viscoelastic effects are quantified.
First Results from the Maljamar Carbon Dioxide Pilot
Authors: Lingane P. J. , McWilliams R. E. , Pittaway K. R.
Published: December 2007

Continuous carbon dioxide injection in the Grayburg/San Andres formations of the MCA unit has been completed; follow-up brine injection began in December 1983. Incremental oil production began in mid-1983 from the Grayburg zone and six months later from the San Andres.

Special features of the inverted five-spot pilot include (a) separate completions in the Grayburg and San Andres zones; (b) fiberglass-cased logging observation wells for in situ monitoring of oil, brine, and carbon dioxide movement; and (c) gamma-ray emitting tracers for improved vertical resolution of flow zones.

The a priori prediction of the flow behavior in the Grayburg reservoir, developed from core and log data from seven closely spaced wells, was not consistent with pressure interference data, nor with the arrival times of tracers at the logging and production wells. At least three different reservoir descriptions match the Grayburg data; the most likely explanation is a change in the effective location of the injection well due to a hydraulic fracture.
Cosurfactant-Enhanced Alkaline Flooding
Authors: Nelson R. C. , Lawson J. B. , Thigpen D. R. , Stegemeier G. L.
Published: December 2007

Many crude oil candidates for enhanced oil recovery by alkaline flooding produce their lowest interfacial tension at very low concentrations of alkali. Alkaline consumption by the rock makes propagation through the oil reservoir of such dilute alkaline solutions prohibitively slow. The dilemma of having to choose between highest displacement efficiency (lowest interfacial tension) and satisfactory displacement rate can be resolved by adding cosurfactants to the alkali. Low concentrations of properly chosen cosurfactants raise the concentration of electrolyte required for minimum interfacial tension to alkali concentrations high enough for satisfactory propagation of the alkaline bank. That is, just as in chemical flooding, a cosurfactant can be used to raise the "salinity requirement" of an alkaline flood.

Activity Maps, similar to the Salinity Requirement Diagrams of chemical flooding, are useful in formulating and understanding the results of cosurfactant-enhanced alkaline floods.

Alkaline flooding systems, formulated by the methods discussed in this paper, recover as much oil in laboratory core floods as well-formulated chemical flooding systems.
Evaluation Coring Results at a Micellar/Polymer Flood
Authors: Milton H. W.
Published: December 2007

The results are presented for three evaluation core tests drilled at the M-1 Project in the Robinson Field of southern Illinois. The cores were taken near three logging observation wells which have been used to follow injected fluid movement through the reservoir in one-quarter of a 2-1/2 acre 5-spot.

Core oil saturation, oil displacement efficiency and vertical conformance are related to slug size, geologic characteristics and reservoir properties. The Robinson sand in the core test wells can be divided into at least three zones that show different fluid movement. These zones are also indicated by the observation well logs.

Sulfonate was detected in all selected core sample extractions. Further analysis showed that the low oil saturation samples had lost more of the water-soluble sulfonate components – that is, the sand had been flushed better by the polymer solution following the micellar slug. Where the slug has been effectively displaced, a considerable reduction in reservoir oil saturation is occurring.
The Effect of Temperature and Interfacial Tension on Water/Oil Relative Permeabilities of Consolidated Sands
Authors: Torabzadeh S. J. , Handy L. L.
Published: December 2007

Relative permeability data for high- and low-tension systems were obtained experimentally at temperatures ranging from 22°C to 175°C. No other data have been reported for high temperatures and low interfacial tensions. Results for high-tension systems at elevated temperatures and for low-tension systems at room temperature are compared with other published data. The results of this study can be used to predict the performance and efficiency of enhanced oil recovery methods in which chemicals are considered for use with hot waterfloods or as steamflood additives. They are of particular interest with respect to steamfloods in viscous oil reservoirs.

Equipment was designed and constructed to measure water-oil relative permeabilities at elevated temperatures and pressures. It can be used for both steady-state and unsteady-state dynamic displacement measurements. The apparatus permits very accurate measurement of fluid saturations volumetrically by monitoring the oil content of the total system using a high pressure, high temperature water-oil separator. Experiments were conducted on fired Berea sandstone cores using n-dodecane and 1% NaCl brine. Aqueous low-concentration surfactant solutions were used to change interfacial tension levels. For the experiments reported here, the fluid pressure was kept constant at 300 psig and the overburden pressure at 650 psig.

The experimental results indicate that relative permeability curves are affected by temperature, especially at low IFT's. For the high-tension system, relative permeability to oil increased and relative permeability to water decreased at a given saturation while residual oil saturation decreased and irreducible water saturation increased with increasing temperature. Water/oil relative permeability ratio decreased with temperature at a given water saturation. These results suggest an increase in the preferential water wettability of sandstone with temperature.

Temperature effects were found to be more pronounced for low-tension than for high-tension systems. Residual oil saturation decreased significantly at higher temperatures, but only a small change in irreducible water saturation was observed. At any given temperature, irreducible water saturation for the low-tension system was lower than that observed for the high-tension system. Relative permeability to oil and water both increased with increasing temperature up to 100°C for the low-tension system. At higher temperatures, a decrease in relative permeability to water was observed, probably due to wettability alteration.

The steady-state technique showed a hysteresis effect in relative permeability curves which tended to diminish at high temperatures and low IFT's. Rate effect was not significant for the rates used in this study. The change in wettability of the rock and reduction of IFT with increasing temperature were important factors affecting the observed relative permeability curves.
Frontal Structure and Stability in Immiscible Displacement
Authors: Jerauld G. R. , Nitsche L. C. , Teletzke G. F. , Davis H. T. , Scriven L. E.
Published: December 2007

A theory of the stability or instability of plane saturation fronts in immiscible displacements is presented which is more realistic than earlier theories. For given two-phase relative permeability functions, capillary pressure function, viscosity ratio, saturation ahead of the front, and allowable front-propagation speed, the displacement-front saturation profile of permanent form is calculated from Rizhik et al.'s (1961) solution by quadrature of the nonlinear convective diffusion equations for two-phase flow with significant capillary effect. Stability of the saturation profile of permanent form with respect to small disturbances in pressure and saturation (as may be caused by minor heterogeneities in a reservoir) is found by solving the generalized eigenproblem to which linear stability theory and finite differencing lead.

The results show that when the front is unstable there is a fastest growing wavelength of disturbance transverse to the flow. Shorter wavelengths are slowed or stabilized by capillary-pressure-gradient-driven flow; longer wavelengths grow more slowly because the transverse pressure gradients driving them are weaker. If the displacing fluid is viscous enough the front is stable, but the larger the scale of disturbance the more nearly it is marginally stable. An earlier theory that approximates the front as a discontinuity agrees roughly but differs in important details, among them the mildly stabilizing effect associated with the saturation profile in the frontal zone.
A Study of the Relationship Between Surfactant/Oil/Brine System Phase Behavior and Chemical Flood Recovery in Short Cores
Authors: Ashrawi S. S.
Published: December 2007

This study correlates the phase behavior of surfactant/oil/brine systems with their chemical flood performance in short cores. The study focuses on the influence of two important system composition variables: viz. the brine salinity and the nominal equivalent weight of a petroleum sulfonate blend. Furthermore, it investigates the influence of the addition of an alkylether sulfate in terms of optimal salinities, increased salinity tolerance and tertiary recovery efficiency.

The oil displacement experiments employ a very fast, near-continuous, constant salinity flooding process in 3-inch long Berea cores, using a microwave instrument to determine the oil saturations. A typical turn-around time for a flooding experiment was seven hours.

Tertiary oil recovery contours are developed in a brine salinity-surfactant equivalent weight space. The region of highest tertiary oil recovery in that space closely matched the region in which equilibrium three-phase systems existed. Optimal salinities and equivalent weights, as defined by the chemical flood with the lowest final oil saturation, were obtained with excellent resolution. More significantly, they closely matched those optimal values obtained under equilibrium conditions from time-consuming solubilization parameter measurements.

The addition of the alkylether sulfate solubilizer had the effects of increasing the optimal salinity, and significantly broadening the three-phase region as well as the region of high tertiary oil recovery. This broadening effect caused a lower resolution in the determination of optimal system variables. In the presence of the solubilizer, a close correspondence between the three-phase region and the region of optimum oil recovery was also observed.

This study introduces a rapid and meaningful technique to determine the EOR potential of surfactants and surfactant formulations. Applications of the results of this work include: the rapid screening of surfactants for enhanced oil recovery processes in specific rock matrices, the design and optimization of surfactant formulations and the quality control of plant-manufactured surfactants and field-blended surfactant formulations.
CO2 Minitest, Little Knife Field, ND: A Case History
Authors: Thakur G. C. , Lin C. J. , Patel Y. R.
Published: December 2007

A joint DOE-Gulf Oil Corporation Minitest of CO2 miscible flooding was conducted in the Mission Canyon formation of the Little Knife Field, North Dakota. In the five-acre minitest area, a central injection and three observation wells were drilled to form a non-producing, inverted four-spot pattern. A 1:1 CO2 WAG injection sequence (preflush water injection, five alternate slugs of CO2 and water, and drive water injection) was implemented. Prior to the CO2 minitest, a detailed reservoir description of the test area was developed through logging, pulse testing and core analysis. Extensive laboratory work had been performed to determine miscibility pressure, swelling and viscosity reduction effects.

The minitest included continuous bottom-hole pressure measurement in all test wells and time-lapse logging to monitor saturation changes as alternate slugs of water and CO2 passed the observation wells. Fluid samples from the observation wells were collected periodically to check for tracers and fluid composition. At the conclusion of drive water injection, a fifth well was drilled behind the CO2 front and pressure-cored to measure the residual oil saturation to the CO2 flood. A Compositional Simulator was used to history match the minitest performance and to evaluate the displacement and sweep efficiency in the project area.

Reservoir simulation models were used at various stages of the minitest: (a) to determine the volume and rate of water injection required to raise the reservoir pressure above the minimum miscibility pressure, (b) to calculate CO2 slug size, WAG ratio and project life, (c) to select the location of the fourth observation well behind the CO2 front, (d) to predict breakthrough times and concentrations of CO2 and water to decide when to log wells and collect fluid samples, (e) to scale the minitest reservoir description to a typical 160-acre, five-spot pattern for predicting recoveries for a waterflood and the CO2 WAG process, and (f) to perform sensitivity studies for studying the effects of layering, vertical communication and other process parameters.
Kinetics of the Chromium(VI)/Thiourea Reaction in the Presence of Polyacrylamide
Authors: Southard M. Z. , Green D. W. , Willhite G. P.
Published: December 2007

The formation of chromium(III)-polyacrylamide gels was followed kinetically using spectrophotometric methods. The rate of chromium(VI) species conversion by thiourea and bisulfite was monitored to find a kinetic model for the oxidation/reduction reaction. The third order model found here shows first-order dependence on chromium(VI) concentration on thiourea and on pH. Additional results of the thiourea study show that a constant amount of chromium(VI) is consumed at gelation regardless of the initial concentration of that species, indicating that the Cr(VI) reduction reaction may be the rate-determining step in gelation. No such model or constant conversion for the bisulfite-reduced reaction could be determined.
The Multiwell Experiment Core Program, II
Authors: Sattler A. R.
Published: December 2007

An unprecedented core analysis program is under way as part of DOE's Multi-Well Experiment (MWX). MWX is a research-oriented field laboratory whose objectives are to thoroughly characterize lenticular tight gas sands and to develop technology for their production. Over 4100 ft (1250 m) of core were taken from three wells separated by only about 115–215 ft (35–66 m) at depth. All major categories of core analysis are reviewed and results through December 1983 are included. Those include routine core analysis, restored state reservoir parameter measurements, electrical measurements, mechanical rock property data, mineralogy, organic maturation, natural fractures, and geochemistry. This paper also describes the laboratory work on core and formation invasion and the development of instruments that were used in the field processing of the core.
Simulation of Real Gas Flow Through Finite-Conductivity Fractures
Authors: Hossain Mehedi , Cady G. V. , Honarpour M. M.
Published: December 2007

Hydraulic fracturing stands as one of the most effective stimulation techniques that were developed to increase the productivity of either damaged wells or wells producing from low permeability reservoirs. The evaluation of fracturing treatment and performance prediction of such wells are, therefore, very important for petroleum engineers. Although various analytical, semi-analytical and numerical solutions to the fluid flow in fractures have been proposed, reliable results are not obtained because of several simplifying assumptions.

The development of a mathematical model to simulate the entire pressure test history of a hydraul-ically fractured gas well is presented. A two-dimensional reservoir model was combined with an one-dimensional fracture model to study the well performance under a variety of operating conditions. In this paper the effects of non-Darcy flow in the reservoir and in the fracture, wellbore and fracture storage, fracture damage, closure stress, gas slippage, and frictional pressure drop in the tubing are investigated. Test results of the model illustrating the effects of each of these factors are also presented.
Reduce Completion Costs by Using Optimum Number of Perforations
Authors: Bucy B.J.
Published: December 2007

There has been a recent trend toward reducing the number of perforations in oil wells that are to be hydraulically fractured. Two benefits of this practice are better control of the fracture treatment and reduced completion costs. This paper presents a method of mathematically calculating the number of performations to be used to obtain the greatest reduction in completion costs. This optimum number of perforations is obtained by equating the perforating cost and the perforation friction cost during the fracture treatment. By reducing the number of perforations to this optimum point the completion costs are reduced. In the case of hydraulically fractured oil wells, the reduction of the number of perforations to this optimum point will have negligible effect on the production capacity of the well.

Introduction

Ever since the introduction of the practice of setting casing through the pay zones and then perforating, there has been the problem of determining the number of perforations that should be used. An early mathematical study was made by Muskat wherein the perforations were considered to be point sinks. The study made a comparison of the theoretical productivity possible through perforations as compared to the theoretical productivity possible in an open-hole completion. Later studies were made using electric analog models wherein the effect of penetration into the formation was considered. These studies indicated that pay zones should be perforated from top to bottom with a density of 8 to 16 shots per foot in order to not seriously restrict production.

The above theoretical studies were made assuming ideal conditions and radial flow drainage with the results expressed as ratios. In actual practice many factors in addition to the number of perforations, such as proration, formation permeability, tubing choke, etc., determine the resultant productivity of a perforated well. Due to these factors, plus other things, such as perforating gun mechanical strength and interference between jet charges, the normal field practice became: perforate pay zones from top to bottom with a reduced density of four shots per foot. Statistical data comparing open-hole completions and perforated completions in one field indicated there were no recognizable differences in performance between the two groups.

Recent articles have advocated the further reduction of the number of perforations in wells that are to be hydraulically fractured. This reduction in the number of perforations results in better control of the fracture treatment, and reduction in completion costs. It appears that there is a present trend in the industry to follow the suggestions in these articles.
A Multi-Level Well Management Program for Modelling Offshore Fields
Authors: Fenter D. J.
Published: December 2007

In reservoir simulation, software referred to as a well management program is used to set well rates and/or pressures for the reservoir model. A well management program for use in modelling multiplatform, multi-reservoir North Sea fields has been developed to allow Esso engineers to investigate alternative field production plans by altering platform facility constraints and field controls. It has been used by Esso in reservoir simulation studies of the complex Brent field in the U.K. North Sea.
Initial Experience With an Underwater Manifold Centre
Authors: Osborne J. M.
Published: December 2007

In July 1983 comingled production from the first two completed wells of the Shell/Esso Underwater Manifold Centre (the UMC), reached the Cormorant Alpha platform. This moment was the culmination of design and development effort which had begun as early as the spring of 1975. But being both the largest subsea system to become operational in the North Sea, and the first designed to the production of several subsea wells, whilst injecting into others, how would the UMC continue to perform?

This paper details the operational experience gained to date with the UMC, tracing its brief history since it was first powered up in September 1982 to the present. This is discussed in the main body of the paper under the headings: Commissioning ExperienceOperating ExperienceReliability and Maintenance Conclusions

The UMC system is briefly described as a preliminary to the above.
Future Small Offshore Oilfield Developments
Authors: Marks V. E.
Published: December 2007

Prediction of the size of offshore oil fields yet to find shows the increasing importance of small fields.

This paper is intended as a general review of the production schemes available for the development of small offshore oil fields. Its aim is to promote development of the technology required to economically exploit the increasing number of small and marginal fields.
Subsurface Safety Systems for TLP Completions
Authors: Calhoun M. B. , Deaton M. , Tamplen J. W.
Published: December 2007

Well completions for tension leg platforms require special consideration in key areas. Standard downhole equipment including subsurface safety valves can be used in a conventional manner from TLP's. Special designs, however, may be required for annular safety systems or sales risers.
Reservoir Simulation of Steam Injection in the Cold Lake Tar Sand
Authors: Peake W. T.
Published: December 2007

A reservoir simulator of steam injection in the Cold Lake Tar Sand has been validated through a history match. The history match consists of 9 steam cycles in two wells during the period June 1978 through October 1980. Block size, fracture length, oil and water relative permeabilities, and pore compressibility were found to have a significant effect upon the simulation results. The simulation results were found to be insensitive to the time step size, heat conduction from the fracture, areal grid, and well productivity index.

A proposed commercial development of the Cold Lake Tar Sand consists of 4 well, 4.13 acre (1.67 × 104 m3) rectangular well patterns. The steam injection program consists of three phases: (1) single well cyclic steaming, (2) on-trend steam drive, and (3) off-trend steam drive. The optimum number of cycles, steam injection rates, and steam slug sizes were obtained. Simulation results for the optimized oil recovery are: a steam/oil ratio of 5–6, an average oil production rate per well of 42 bbl/d (6.7 m3/d), and a recovery of 45% of the original-oil-in-place in 9.2 years.
Improved Bulk Blending Techniques for Accurate and Uniform Cement Blends
Authors: Pace R. S. , McElfresh P. M. , Cobb J. A. , Smith C. L. , Olsberg M. A.
Published: December 2007

Two of the major factors affecting cement slurry performance are the concentration of additives and their distribution throughout the dry cement blend. Consistometer thickening time tests on one or two batches of the cement are used to monitor the cement blends. Studies conducted have proven that these tests do not necessarily reflect the uniformity or the correct concentration of additives in the blend. To improve the quality of the bulk blending of cement, researchers developed on-site methods to verify the additive concentrations of each batch blended for uniformity and accuracy. They also investigated the effects of the current dry blending procedures, transportation, and air blending on the distribution of such additives as retarders, fluid loss agents, weighting agents, and salts.
The Use of a Medical Computer Tomography (CT) System To Observe Multiphase Flow in Porous Media
Authors: Cromwell V. , Kortum D. J. , Bradley D. J.
Published: December 2007

The value of Computed Tomography (CT) to analyze fluid flow in porous media has been verified, using a medical CT system. A series of simple displacement experiments using Danian chalk and Berea sandstone are presented to prove the feasibility of this concept. Radial and axial cross sectional views of the cores show movement of fluid fronts and changes in saturations at fixed locations. The limitations of the medical computer software provided with the first generation CT system used in this study are discussed and some possible enhancements of the equipment and software are proposed.
Numerical Simulation of Micellar Polymer Field Processes
Authors: Dogru A. H. , Mitsuishi H. , Yamamoto R. H.
Published: December 2007

This paper discusses the numerical simulation of field processes for micellar-polymer flooding. Two different models, along with their mathematical formulations, are presented. The first model is a limited compositional model. This type of a model requires a minimum amount of thermodynamic data and can potentially be applied to larger field problems. The second model is a two-dimensional, four-phase, ten-component, compositional model. The primary areas of use for the compositional models are the design of the slug, the planning of overall process strategy, and the investigation of the effect of various thermodynamic process variables on the oil recovery. Although the compositional models are not well suited for field scale simulation, information obtained from these models can be extrapolated to field scale. Specifically, this paper discusses the systematic use of various reservoir models in various phases of the project for an effective field recovery prediction. The numerical examples for each model use are included.
Operating Plan for Lena Guyed Tower
Authors: Percy J. P. , Massey M. W. , Barth J. R.
Published: December 2007

Under extreme environmental conditions, the compliant nature of the guyed tower can have an impact on drilling and production operations, as it results in relative vertical motion of the wellheads, as well as platform deck tilt and acceleration. Production and drilling equipment and operations on the LENA Guyed Tower therefore required special consideration in order to ensure safety and continuity of operations.
Evaluation of a Centrifuge Drill-Cuttings Disposal System With a Mineral Oil-Based Drilling Fluid on a Gulf Coast Offshore Drilling Vessel
Authors: Jackson S. A. , Kwan J. T.
Published: December 2007

Discharge of diesel oil based drilling fluids to ocean waters is under increasing scrutiny by industry and by regulatory agencies. Industry and agency sponsored research indicates that the presence of diesel oil in drilling muds contributes to toxicity levels which may not be acceptable for discharge. Some proposed National Pollution Discharge Elimination System (NPDES) general permits ban the discharge of diesel oil muds. Because of increasing concern over the discharge of drilling fluids containing diesel oil, there is considerable interest in the industry in developing diesel oil substitutes.

Recent technological advancements in mineral oil invert emulsion drilling fluids offer promise of a substitute for diesel oil based muds. These mineral oil muds have performed as well as diesel oil muds in most instances. Mineral oil based muds have low toxicity to test species. Toxicity of mineral oil muds compared favorably with water based muds which are routinely approved for offshore discharge.

Because mineral oil muds are a relatively new development, very little data are available to the various regulatory agencies (EPA, MMS, and USCG) concerning the use of these fluids. This has resulted in cautious positions by these agencies in approving the discharge of mineral oil muds.
Itabirite: An Alternative Weighting Material for Heavy Oil-Base Muds
Authors: Scharf A. D. , Watts R. D.
Published: December 2007

This paper assesses the benefits of itabirite (hematite) as a weighting material in heavy oil base systems. A laboratory investigation was conducted to obtain information on a comparative basis between barite and itabirite. Rheological properties and abrasiveness were studied and field results were predicted.

As a result of the lab studies, lower field rhe-ology (i.e., PV, YP and Gel Strength) and a slightly more abrasive nature are predicted. Increased penetration rates and improved bit hydraulics are expected. Increased penetration rates and a greater tolerance to drill solids should reduce overall mud cost and well cost.

Upon completion of the laboratory study, field tests were made in a development area. Offset information on wells drilled with barite was studied, and variables such as drilling rigs, mud company, solids control equipment, bits, and mud programming were kept as consistent as possible with the exception of itabirite as the mud weighting agent.

Results indicate an increase in penetration rates as compared to offset wells, especially in mud weights exceeding 15 lbs/gal. Plastic viscosity was lower as predicted, mud cost slightly decreased, and abrasion did not appear excessive on pump liners and and pump parts. The efficiency of the solids control equipment was increased as shown by the maintenance of a lower percentage of solids in the mud and reduction of the percentage of low gravity solids.
The Effects of Dispersion and Phase Behavior on Unfavorable Mobility Ratio Displacements
Authors: Giordano R. M. , Salter S. J.
Published: December 2007

A compositional simulator is used to show how dispersion and phase behavior influence the stability of laboratory-scale displacements in which the mobility is unfavorable. Major emphasis is placed on analyzing the role of transverse dispersion in this process. The various flow patterns that can occur during fingering are shown as well as the composition history of the process during an unstable flood. For the process under study here, simulation results predict that the upstream side of the oil bank is extremely stable. Any fingers that form upstream of this front are unable to distort the stability of the oil bank. Some mechanisms for lateral finger movement in the core are explained and the effect of discretization on simulating these movements is shown. Finally, the effect of transverse dispersion on flow in high permeability streaks is illustrated.
Accurate Prediction and Corrections of Gellation Problems in Oilwell Cement
Authors: Brinkley J. F. , Mikkelson M. S.
Published: December 2007

Gel strength and rheological properties are used to determine certain characteristics of oilwell cement slurries. Historically, rheological measurements of these cement slurries have been used to determine their pumping characteristics. However, the use of standard rheologies, plastic viscosity (μp) and yield point (yp) alone have not been sufficient to explain the gellation problems. Because of this a modified gel strength procedure has been developed, that together with API rheology tests can be used to accurately predict gellation problems with oilwell cement slurries.
Testing Exploration Wells by Objectives
Authors: Barnum R. S. , Vela S.
Published: December 2007

Many papers have been published extending the theoretical understanding of pressure transient analysis. Most of these papers have concentrated on analysis of buildup tests for reservoir permeability, wellbore damage, and reservoir pressure. In many cases, the state of the art of analytical methods is far superior to the quality of the data obtained with present day procedures and instrumentation. This paper reviews the state of the art of testing exploration wells and presents a systematic approach to better formation evaluation. This systematic approach consists of establishing specific objectives for obtaining formation evaluation from well testing. Once the objectives are set, guidelines are given to design the test to meet all the objectives. The responsibility of test design rests on a well trained test engineer who also has the responsibility of test supervision, data quality control, data analysis, and test documentation. Guidelines are presented for procedures and instrumentation and a specific field example is presented that illustrates how to plan and conduct an exploration well test.
World Demand for Crude Oil
Authors: Omar A. E.
Published: December 2007

The purpose of this study is to determine the likely changes in the world demand for crude oil in response to predictable changes in the levels of domestic economic activity in the major oil consuming regions of the world. A world model of the demand for crude oil using an econometric framework was constructed. The model is expected to forecast domestic and import demand for crude oil among the major regions, using assumed levels of macro-economic activity, prices and changes in stocks.

This model was also designed to assess the sensitivity of the future demand and price of oil because of its uncertainty associated with most econometric and engineering studies of the demand and price responsiveness of oil/energy market.

This model will be helpful in regulating the oil prices for better planning and development to the producers and consumers alike. As a result of this model, low-income countries would benefit most.
Dubai Gas Lift Automation
Authors: Coltharp E. D. , Khokhar M.
Published: December 2007

Dubai Petroleum Company has recently installed a computer gas lift surveillance and gas lift gas injection control system in the Fateh and S.W. Fateh Fields located in the southern part of the Arabian Gulf.

This system is the fourth generation of the computer control system installed in California in 1971 by Conoco, Inc. This paper describes the advantages and problems in this system to monitor and control the gas lift operation of 116 wells through 30 intelligent remote terminal units (RTU). In addition, this system monitors the condition of critical operational items such as emergency shut-down (ESD), fire detection, hydraulic systems, compressors, production rates, etc.
Rock/Crude-Oil Interactions and Wettability: An Attempt to Understand Their Interrelation
Authors: Cuiec L.
Published: December 2007

To emphasize the occurrence of non-water-wet reservoirs, a literature review of this topic is made followed by a description of our findings concerning the evaluation of the wettability of some 20 reservoirs from Europe, North Africa and the Middle East. Then this paper describes various experimental contributions to the understanding of rock/crude-oil interactions which are responsible for the occurrence of such reservoirs.

The major role of heavy fractions, especially asphaltenes, has been shown in various ways, whereas low-boiling-point cuts (< 350 °C) were not able to induce wettability changes. Moreover, it appears that, among intermediate fractions of a crude oil, some may change the surface properties of rocks, depending on the type of rock. Our research also confirms that various pure-acid and basic-organic compounds with low molecular weight are not able to induce wettability changes in various kinds of porous media.
Use of Reservoir Performance Analysis in the Simulation of Prudhoe Bay
Authors: O'Brien D. G. , Brown M. E. , Lederer M. C.
Published: December 2007

Reservoir and well performance analysis have made a large contribution to understanding the Sadlerochit reservoir at Prudhoe Bay. The means by which this information has been efficiently used in day-to-day decision-making is described. Its application to the history matching process of a full field numerical simulator is discussed. A method of developing a reservoir management strategy based on performance analysis, and independent of the full field simulator, is presented. A means of incorporating this strategy into full field simulator predictions is suggested.
Applications of a Thermal Simulator to Field Cases
Authors: Corre B. , Eymard R. , Quettier L.
Published: December 2007

Some field applications of a thermal, pseudo-compositional, fully implicit simulator are presented. A brief description of the simulator outlines its main physical and numerical features. A steam-flood in a 3D reservoir containing fractured zones shows the efficiency of the implicit formulation in handling very heterogeneous cases. With a 9-point scheme, the grid orientation effects disappear. Furthermore very high contrasts of temperature are solved by this model in a reservoir where convective movements into 2 horizontal and 2 vertical connected fractures induce the meeting of hot and cold flows. Finally, the interpretation of temperature surveys allows the determination of the real path of the injected fluid through the cementation of a well completion.
Progress Report Of The Neutron Lifetime Log Application In California
Authors: Millis C.W. , Wood R.D.
Published: December 2007

A series of field tests were performed to establish the feasibility of introducing Neutron Lifetime Logging into California on a commercial basis as an aid to solving complex reservoir problems. Prior to the tests, there was apprehension that the fresh connate waters and mixed lithologies would present unsurmountable barriers to reliable formation evaluation. The results of the tests definitely proved that the Neutron Lifetime log is capable of identifying oil and gas bearing zones from water zones in California. Six examples are presented in this paper showing different approaches to Neutron Lifetime evaluation and the resulting production from recompletion.

The Neutron Lifetime relies on the principle that thermal neutrons generated from a pulsed source will be captured by formation materials. The rate of capture depends upon the capture cross section (S) and the amount of material present.
Vortex Drilling: A New Field Practice
Authors: Hayatdavoudi A. , Akhigbe A. , Ghalambor A. , Okoye C. U. , Nini C. J.
Published: December 2007

In Part (1) of this paper, we discussed the theoretical development and have presented some laboratory data. Part (2) - the last part - presented here deals with the case histories, economic models and economic analysis of wells drilled with and without the Downhole Vortex Generator (DVG).

The analysis of field data shows that for 9-7/8" intermediate holes, a cost per foot reduction of 18% - 26% is achievable. However, due to lower vortex intensity in 6-3/4" production holes, the cost reduction may or may not be possible.
An Updated Examination of Gas Sweetening by the Iron Sponge Process
Authors: Anerousis J. P. , Whitman S. K.
Published: December 2007

A detailed evaluation of gas sweetening via iron sponge (hydrated iron oxide) has been undertaken due to the apparent lack of comprehensive engineering, research, and field data related to this process. Key areas reviewed include composition of the sweetening media, unit design considerations, and operational parameters. The investigations discussed in this paper provide quantifiable proof that the iron sponge process continues to be a viable alternative for hydrogen sulfide and mercaptan removal, provided the sweetening equipment is properly designed and operated.