bluuebunny/crossref_metadata_2025 huggingface dataset:
Review of Phase A Steam-Assisted Gravity-Drainage Test
Authors: Edmunds N. R. , Kovalsky J. A. , Gittins S. D. , Pennacchioli E. D.
Published: December 2007

This paper presents a case history of the Phase A steam-assisted gravity-drainage (SAGD) test conducted by the Alberta Oil Sands Technology & Research Authority (AOSTRA) at its underground test facility (UTF). Reservoir description, the recovery process, design of wells and other critical hardware, production operations history, and performance analysis are discussed. Phase A demonstrated a commercially viable combination of recovery, production rate, and steam/oil ratio (SOR). Completions design and production engineering progressed significantly. Phase B scaleup considerations and commercial economic projections also are discussed.
Influence of Wettability on Two- and Four-Electrode Resistivity Measurements on Berea Sandstone Plugs
Authors: Wei Jun-Zhl , Llle Ole B.
Published: December 2007

Two- and four-electrode resistivity measurements were conducted on water- and oil-wet Berea sandstone plugs for different saturation directions with a steady-state flooding procedure. The data from nine plugs indicated that reliable resistance values can be obtained on water-wet cores with both two- and four-electrode methods. On oil-wet cores, however, two-electrode measurements yielded higher resistance values than those from the four-electrode method because of end effects and contact resistance, especially for low water saturations. In addition, the saturation history substantially influenced the resistivity measurements of oil-wet cores. The four-electrode technique is better for oil-wet core resistivity measurements because it ensures that correct Archie saturation exponents are derived.
Methods of Detecting and Locating Tubing and Packer Leaks in the Western Operating Area of the Prudhoe Bay Field
Authors: Michel C. M.
Published: December 2007

Evaluation methods have been developed to detect cases of tubing/ annulus communication. Temperature, spinner and noise logs, as well as fluid level detection equipment, are used under a variety of flow conditions. Step-wise procedures are provided.
Steamflooding Cold Lake Oil Reservoirs Through a Bottomwater Zone: A Scaled Physical Model Study
Authors: Nasr T. N. , Pierce G. E.
Published: December 2007

A series of experiments was conducted in one-eighth of a five-spot-pattern, high-pressure, scaled physical model to evaluate the potential of steamflooding oil-sand reservoirs through a bottomwater zone in Cold Lake, Alta. During the experiments, steam was injected into the bottomwater zone at a constant rate until steam breakthrough occurred at the production well. The steam injection rate then was reduced to limit steam production. Results demonstrate that the process is influenced by the steam injection flow rate because of the important role played by gravity override. Increasing the steam injection rate beyond an optimum value results in decreased oil/steam ratios (OSR's) and reduced final oil recovery because steam channels to the production well. A delay in oil production was noticed in all experiments. A moving-heat-source, gravity-override, analytical model was used to investigate the mechanisms of reservoir heating in the presence of steam-gravity override. In addition, the thermal efficiency of the process, determined from the experiments and extrapolated to field conditions, was compared with predictions from Prats' thermal efficiency model. Prats' model predicted the measured thermal efficiency reasonably well at lower injection rates. As the injection rate increased, however, larger differences between Prats' model and the experiments were noticed.
Steam-Foam Mechanistic Field Trial in the Midway-Sunset Field
Authors: Friedmann Francois , Smith M. E. , Guice W. R. , Gump J. M. , Nelson D. G.
Published: December 2007

A one-pattern, steam-foam mechanistic field trial was conducted in Section 26C of the Midway-Sunset field (upper Monarch sand). The test objectives were (1) to understand the mechanisms of steam diversion caused by foam under reservoir conditions, (2) to establish whether foam can exist in-depth away from the injection well, and (3) to measure incremental oil that can be attributed to foam. Surfactant was injected with steam and nitrogen continuously, and bottom-hole injection pressure (BIHP) increased from 100 to 300 psig, indicating good foam generation. Better steam distribution across the injector's perforations occurred when foam was generated. Improvements in both vertical and areal sweep efficiency of steam were observed. Substantial temperature and gas saturation increases coincided with surfactant breakthrough and local reservoir pressure increases at observation wells. Complementary laboratory core-floods showed that foam generation could occur at low-pressure gradients, which are typical of in-depth conditions. Both laboratory and field data were interpreted as evidence that the in-depth presence of foam was the result of local generation wherever surfactant, steam, and nitrogen were present, rather than propagation of a foam bank generated near the injector. Some oil-production increase was also observed during the test; however, an accurate quantitative estimate of incremental oil owing to foam was difficult to establish.
A Performance Evaluation of Canada's Snipe Lake/Beaverhill Lake A Pool
Authors: Springate G. L. V. , Muir I. D. , Caldwell T. R.
Published: December 2007

This paper describes the evaluation of the production performance of the Snipe Lake/Beaverhill Lake A (BHL-A) pool. The purpose of this investigation was to determine the reasons behind the pool's low projected recovery (32%) relative to similar pools (40%) and to recommend steps to remove the causes. This work was initiated because the pool's production is declining under the existing depletion scheme (essentially a downdip waterflood). The evaluation involved simultaneous geological and engineering investigations that improved the quality of data interpretation and the timeliness of the effort and reduced the overlap of work that otherwise might have occurred. The detailed reservoir model developed indicated that the production performance is controlled by the pool's geology. Fluid movement is restricted vertically between reservoir cycles and horizontally within the major reservoir cycle. An analysis of previous infill drilling and producer-to-water-injector conversions demonstrated that incremental recovery of oil was achieved; 4.5% (422× 103 m3) from infill wells on 32-ha well spacing and 6.0% (740× 103 m3) from increased water injection. Converting the entire pool to a 65-ha pattern waterflood will increase the recovery by 1.9% (900× 103 m3). A 32-ha pattern waterflood has the potential of 5.6% (1740×103 m3) additional recovery.
An Analysis of Uncertainty in Directional Surveying
Authors: Walstrom J.E. , Brown A.A. , Harvey R.P.
Published: December 2007

Knowledge concerning the position of the bottom of a directionally drilled hole is uncertain. This uncertainty can be measured quantitatively either by analysis based on principles of probability and statistics, or by Monte Carlo simulation using a computer that yields a pattern of possible bottomhole locations.

Introduction and Model Description

In view of the large number of wells directionally drilled from offshore platforms and urban drillsites, greater interest is being focused on the directional survey and on the uncertainty inherent in calculating the position of the bottom of the hole, or other benchmarks in the wellbore. Of the two methods presented here for evaluating this uncertainty, the first is analytical and uses the principles of probability and statistics. The second method uses Monte Carlo simulation to generate a pattern of the scatter of possible bottom-hole locations. possible bottom-hole locations. Both methods are based on a model for which the usual assumption is made that the curvilinear axis of the wellbore is adequately represented by a large number, M, of linear segments joined end to end from the top to the bottom of the hole and closely following the course of the hole. The errors due to this approximation are assumed to be negligible and are not studied here. One form of the model is to consider that for a given hole there exists a perfect set of data describing it, of the above form. Each linear segment has an angle of inclination with the vertical Ii in radians, an azimuthal angle from true north Ai in radians, and a length Si, in feet. The subscript variable, i, extends from 1 to M.

Each of the M linear segments representing the axis of the wellbore has three components in the X, Y, and Z directions. These components are calculated from the equations:....................(1)

The bottom-hole coordinates as determined from the reference set of data for the wellbore are given by the following for i = 1 to M:..........(2)

A directional survey instrument, lowered into the wellbore to the M segments, or stations, measures the values of the Ii and the Ti.

In general, because of errors from various sources, the resulting angular measurements will not be precisely equal to the I, and Ai. Random variables Ii precisely equal to the I, and Ai. Random variables Ii and Ai are therefore considered with associated probability density functions fi(Ii) and gi(Ai), probability density functions fi(Ii) and gi(Ai), respectively, which represent the distributions of potential survey measurements for this hole. Since it is assumed that the values Si are accurately measured they are treated deterministically.

The random variables corresponding to the surveyed bottom-hole coordinates are given, for i = 1 to M, by:............(3)

P. 515
Unstable Two-Fluid Flow in a Porous Medium
Authors: Varnon J.E. , Greenkorn R.A.
Published: December 2007

This paper reports an investigation of unstable fingering in two-fluid flow in a porous medium to determine if lambda the dimensionless finger width, is unique For a viscous finger A is the ratio of finger width to the distance between the tips of the two trailing fingers adjacent to the leading finger. For a gravity finger lambda is defined as the ratio of finger width, to "height" of the medium perpendicular to hulk flow. This work confirms previous experiments and existing theory that for viscous fingering lambda approaches a value of 0.5 with increasing ratio of viscous to interfacial force. However, for a given fluid pair and given, medium, this ratio can he increased only by increasing the, velocity. Experiments on gas liquid systems show that the asymptotic value of lambda with velocity is not always 0.5. Apparently, for gas-liquid systems, the influence of the interfacial force cannot always he eliminated by increasing the velocity. For such systems lambda is a function of fluid pair and media permeability. If the gravity force normal to the hulk permeability. If the gravity force normal to the hulk flow is active, it damps out the viscous fingers except for an underlying or overlying finger. The dimensionless width of this gravity finger strongly depends on velocity and height of the medium, as well as the fluid and media properties. The existing experiments and theories are reviewed and the gravity, stable, and viscous flow regimes are described in view of these experiments and theories. The existence of a gravity-dominated unstable regime, a gravity-viscous balanced stable regime, and a viscous-anminated regime was demonstrated experimentally by increasing flow velocity bin a rectangular glass head model. Asymptotic values of the dimensionless finger width were determined in various-sized Hele-Shaw models with gravity perpendicular and parallel to flow. The dimensionless perpendicular and parallel to flow. The dimensionless finger width lambda was determined as a function of applied force, flow resistance, and fluid properties. The results are interpreted dimensionally. Some comments are made concerning possible scaling and meaningful extensions of theory to describe these regimes in three-dimensional flow. Previous description of unstable two-fluid flow in porous media is mainly restricted to studies of viscous-dominated instability. The direction of this study is to provide data and understanding to consider the more realistic problem of predicting flow in three dimensions that may result in instabilities that are combinations of all, four flow regimes.
Influence of Rock Heterogeneities on Fracture Geometry in the Green River Basin
Authors: Mukherjee Hemanta , Morales R. H. , Denoo S. A.
Published: December 2007

Constant-height models, in the absence of significant barrier stresses, frequently overpredict fracture half-lengths. This has been a problem in the fracture design of the Frontier and Dakota formations in the Greater Green River basin. Both formations often experience unlimited fracture-height growth as a result of a lack of barrier-stress contrast. This paper presents some of the implications of uncontained fracture-height growth in these formations on fracture design through 2D and 3D fracture geometry modeling. The effects of the minimum in-situ-stress profile, Young's modulus profile, and fluid-loss contrast on the fracture geometry evolution are studied. Actual field example data from a Frontier well are used for the sensitivity analyses.
A Method To Estimate Multizone Injection Profiles During Hydraulic Fracturing
Authors: Elbel J. L.
Published: December 2007

When two or more fractures are created during multizone fracturing, proppant penetration in some zones may be inadequate. The injection rate into each zone is governed by fracture height, rock modulus, fluid loss, stress contrasts, and perforation friction pressure.
Preventing Lost Circulation in Severely Depleted Unconsolidated Sandstone Reservoirs
Authors: Ali Aziz , Kalloo C. L. , Singh U. B.
Published: December 2007

This paper discusses the field application of a blend of lost-circulation materials (LCM's), in a water-based drilling fluid to drill through multiple severely depleted, unconsolidated sandstone reservoirs. Simple laboratory tests are documented to show the sealing effectiveness of the LCM blend. Major benefits of the LCM blend include lost-circulation prevention, elimination of intermediate-drilling-casing strings, and substantially lower well costs.
Experiences in Automating in Pipe-Handling Functions
Authors: Boyadjieff G. I. , Merit M. A.
Published: December 2007

Rig automation projects can benefit from the experiences developed during the successful automation of rig pipe-handling equipment. The data provided were derived from the operation and development of iron roughnecks and pipe-handling systems in the field. This paper includes a study of failure mechanisms and how they affect reliability, presents maintenance experiences to show the impact of automation on crew capability and training, and describes many operational and design pitfalls.
A Method for Handling Gas Kicks Safely in High-Pressure Wells
Authors: Low E. , Jansen Case
Published: December 2007

The risk of overloading an atmospheric mud/gas separator (MGS) during high-volume gas kill operations can be minimized. This paper presents the theory and procedure for minimizing this risk for high-temperature/high-pressure (HT/HP) wells. The method can be used to set criteria for selecting the kill method and for separator sizing.

Introduction

The number of HT /HP wells being drilled in the North Sea has increased rapidly. Pressures >15,000 psi are common with associated temperatures>350°F. The drilling and exploitation of these reservoirs have been described as the new challenge to the drilling industry. However, serious well-control incidents have compelled the industry to re-examine the equipment and procedures used to drill these wells.

This paper examines a major shortcoming identified recently: the ability of rig equipment to separate and vent large gas volumes from mud safely. Venting rates from kicks in high-pressure wells can approach the equivalent production of a commercial gas well.

If the separator is overloaded, gas will be blown back into the shale shaker room and other mud-processing facilities, creating an extremely hazardous environment with a high explosion risk. Also, live crude, condensate, and drilling mud will be expelled by the gas through the gas vent line. On offshore rigs, where the vent line often discharges at the top of the derrick, the liquids will fall back to the drilling rig or platform. This creates a fire or explosion hazard. The volatile condensate/oil mixture will accumulate close to the deck in any void space and can be ignited by a spark. The hazards of MGS blowdown are apparent.

High reservoir pressures and temperatures increase the surface gas volume per unit volume of gas influx. The ability of rig gas-processing equipment to handle such increased volumes concerns the industry. Normal practice does not take into account the limitations of the separator but instead concentrates on well control, assuming that the MGS can handle whatever gas volume is present.

The problem is clear. As we continue to explore for oil and gas in deeper and higher pressure reservoirs, we often exceed the safe operating limits of the MGS. Separator modification and redesign has improved its capacity considerably, but space restrictions, especially on mobile rigs, impose an inherent limitation. Our lack of understanding of the complex separation process has done little to improve operating procedures and practices.
Computer Simulation of the Reverse Circulation Well Control Procedure for Gas Kicks
Authors: Miska S. , Beck F. E. , Murugappan B. S.
Published: December 2007

A computer simulator was developed and used to evaluate reverse circulation as a potential well-control procedure during drilling. Potential advantages of reverse circulation verified by the simulator include lower casing pressures and smaller cumulative pit gains. In addition, kick fluids are removed from the well much faster than with conventional kill procedures. Several equipment modifications will be required to implement the reverse-circulation kill procedure.
Installation of STAR Platform
Authors: Søgaard Preben , Lytzen Peter
Published: December 2007

During late Summer 1990, Mærsk Oil & Gas A/S installed the first slim tripod adapted for rig (STAR) satellite platform in Dagmar field in the North Sea by means of a jackup rig. This installation successfully completed the STAR project, and this paper describes the planning and actual installation of the Dagmar satellite platform, a concept that is fully applicable worldwide where a small wellhead platform is needed in shallow water and where crane barges are not readily available.
Underground Flow Well Control: The Key to Drilling Low-Kick-Tolerance Wells Safely and Economically
Authors: Wessel Michael , Tarr Brian A.
Published: December 2007

The minimum acceptable kick tolerance can be quantified on the basis of the likelihood and consequences of an underground-flow well-control incident. Safe and economical casing points can be selected on the basis of the minimum acceptable kick tolerance required to drill the next hole section. For sections with a known but manageable underground flow potential, necessary unconventional well-control contingency plans can be developed. This new approach to well control has the potential to reduce drilling costs by significantly reducing the likelihood of major drilling-related well-control incidents.
Use of Advanced Pattern-Recognition and Knowledge-Based System in Analyzing Dynamometer Cards
Authors: Schirmer P. , Gay J. C. , Toutain P.
Published: December 2007

A quick and accurate identification of downhole problems is essential in rod pumping to minimize operating costs and to maximize oil production. TOTAL-CFP developed a system to assist engineers in day-to-day oilfield operations in rod pumping. The system will make rod-pumping expertise available to field operations personnel. It provides a tool for improving data analysis and can be used as a training aid for engineers dealing with rod-pumping wells for the first time. This system has three subsystems: a dynamogram acquisition system, a dynamogram management system, and a knowledge-based system.

This paper presents the knowledge-based system, which is used to diagnose downhole problems and to suggest corrective actions. To achieve these goals, the system applies advanced pattern-recognition techniques that consist mainly of structural pattern-recognition methods and hierarchical data structures called quadtrees. The diagnostics and recommendations are based on the analysis of surface dynamometer and downhole cards. The interface between the user and the system is very friendly. The system provides the user with graphical explanations of its diagnostics. The system prototype was installed in March 1991 and the specifications of the final version are planned for the end of this year.
Concrete Structures for Development of Offshore Fields
Authors: Gudmestad O.T. , Warland T.A. , Stead B.L.
Published: December 2007

Concrete structures represent competitive solutions for developing many offshore fields. They are of particular interest when storage is required and as floating support structures. Furthermore, concrete reusable platforms may represent cost-saving solutions for many applications. To design optimum structures, designers must be realistic with respect to the structural capacity of concrete for offshore use.

Introduction

Experience in the North Sea has shown that concrete support structures are competitive with steel jacket structures in terms of initial investments and maintenance costs. This experience is considered relevant for other areas, particularly for countries that must import steel, for icy areas, for offshore areas without infrastructure, for places where oil storage facilities are required, and for areas where large crane vessels are not available to lift heavy steel structures or large topside modules. Furthermore, concrete floaters [tension-leg platforms (TLP's) and catenary anchored structures] are attractive as minimum-cost solutions for deepwater applications.

This paper discusses the requirements and infrastructure needed to design and fabricate concrete structures. Particular attention is given to availability of cement, aggregate, reinforcement steel, and prestressing cables. This paper also discusses design competence and required computer facilities, as well as the availability of barges, a shipyard dock, or a special-purpose construction dock. We describe the fabrication, installation, and removal processes. Removal is becoming increasingly important in a world gradually becoming more aware of environmental stability. We give examples of efficient designs suitable for optimum development of small fields and fields requiring storage. These examples include traditional concrete structures constructed with form work or slip forming. Furthermore, novel concrete truss structures fabricated by joining precast tubes and nodes by prestressing cables and grout are discussed. We provide charts that give concrete volumes for a range of applications to enable operators to perform their own economic analyses.
Development Drilling Problems in High-Pressure Reservoirs
Authors: French F.R. , McLean M.R.
Published: December 2007

The successful drilling of a well relies on the correct choice of mud weight after consideration of the collapse and fracture gradients in each hole section. Collapse and fracture gradients and the formation pressure determine the allowable mud weight that can be used to drill a formation. Here, attention is focused on the fracture gradient and its interpretation and variation with hole orientation. We show that interpretation of the fracture gradient in exploration and appraisal wells may not be sufficient to evaluate development options safely. We give a case study of a central North Sea over pressured reservoir to highlight this problem. We conclude that the industry needs to consider the use of microfracturing to resolve the uncertainty inherent in planning development wells in overpressured reservoirs.

Introduction

The successful drilling of a well relies on good planning and consideration of many factors, including mud weight. Historically, mud weight was chosen primarily to prevent the influx of formation fluids. Over the past 2 decades, much attention has been given to the role of mud weight in preventing hole collapse and its adverse effect on inducing mud losses. Fig. 1 depicts extreme wellbore instability conditions where an insufficient mud weight leads to hole collapse because of compressive wellbore failure and too high a mud weight leads to formation breakdown because of tensile failure. Historically, hole collapse and unintentional fracturing have been considered in wellbore stability studies. The majority of published literature has focused on prediction and prevention of hole collapse. Although we discuss hole collapse, our primary focus is the fracture gradient.

Minimum Static Mud Weight

The minimum static mud weight required to drill a well is the larger of the static mud weight required either for well control or to prevent compressive wellbore failure.

The static mud weight required for well control is equal to the formation pressure plus a safe overbalance. The minimum safe overbalance is generally accepted to be 200 psi.
Determining Pump Wear and Remaining Life From Electric Submersible Pump Test Curves
Authors: Divine D. L. , Lannom R. W. , Johnson R. A.
Published: December 2007

The remaining useful life of an electric submersible pump (ESP) is an important economic consideration in deciding whether the used pump should be returned to service without repair. This paper presents quantitative and qualitative techniques to determine the type and amount of wear that a pump has experienced from analysis of pump test data. This paper discusses methods of categorizing used pumps, depending on the wear and associated performance deterioration. This work also describes failure modes, pump reliability, and the concept of pump (product) infant mortality. We show that a used pump can be more reliable and have a longer run life than a new or rebuilt pump. We use test data, tear-down analysis, and a case history to develop these concepts.
Effects of PDC-Bit Selection and Mud Chemistry on Drilling Rates in Shale
Authors: Hemphill Terry , Clark R. K.
Published: December 2007

Full-scale drilling tests were run to evaluate the effect of mud chemistry on penetration rates in Pierre shale cores. Two poly crystalline-diamond-compact (PDC) bits and nine different muds were used in the tests. In addition to penetration rate, occurrence of bit balling with a given mud type was studied. Results indicate that bit type and mud chemistry affect penetration rates and bit balling significantly.
Enhancement of In-Situ Combustion by Steam Stimulation of Production Wells
Authors: Galas C. M. F. , Ejlogu G. C.
Published: December 2007

Steam stimulation of individual wells was used to improve the performance of an in-situ combustion project operated by BP Resources Canada Ltd. in the Cold Lake oil-sand deposits of northeastern Alberta. In addition, steam was used to protect production wells that were threatened by the combustion front or had experienced oxygen breakthrough. The effectiveness of these steam uses varied. This paper describes the strategy developed for the use of steam injection and case histories and draws conclusions on how to use steam injection for maximum effect.
Long-Term Production Results of Polymer Treatments on Producing Wells in Western Kansas
Authors: Moffitt P.D.
Published: December 2007

This paper describes the analysis of the long-term oil production performance of 37 near-well polymer treatments on 26 producing wells in western Kansas to determine incremental oil recovery resulting from the treatments. Estimated incremental oil recovery from the 37 treatments was 76,500 STB of oil from 39,600 Ibm of polymer injected, or 1.93 STB/lbm of polymer injected. The polymer treatment types giving the best oil recovery performance were solutions of anionic polyacrylamide (ungelled) and cationic polyacrylamide gelled in situ with the chromium reduction/oxidation process. Both gave incremental oil recoveries of 2.6 STB oil/Ibm of polymer injected and had average treatment lifetimes exceeding 1 year.

Introduction

Polymer treatments of injection and production wells have been used extensively for fluid diversion and to increase oil recovery. Injection of high-molecular-weight polymers increases the viscosity of the injected water and reduces the permeability of the porous medium to water. In producing-well treatments, the injected aqueous polymer solution preferentially flows into zones that exhibit high permeability to water and subsequently restricts the flow of water when the well is put back on production. Polymer injection has two effects: the water production rate decreases substantially and the pressure drawdown into the wellbore often increases greatly, resulting in an increased oil production rate.

During the 1970's, Phillips Petroleum Co. conducted 37 polymer treatments on 26 producing wells in western Kansas. All but one of the treatments were on wells completed in the Arbuckle dolomite formation. The formation has been characterized as a highly fractured, vuggy dolomite with varying amounts of chert and with reservoir characteristics varying from field to field throughout the Central Kansas Uplift. Permeability ranges from 50 to 5,000 md; porosity ranges from 1% to 20%, with an average of 15%. The oil zone is estimated to be 5 to 50 ft thick; the total Arbuckle zone is up to 300 ft. Oil viscosity ranges from 3 to 13 cp. The reservoir drive mechanism is primarily bottomwater drive, and the wells are completed at the top of the formation to delay the onset of water production. Water production comes primarily from coning. Because of the natural fracture network, vertical permeability is high and there are few vertical barriers to restrict water coning.
Theoretically Indicated Methods of Wetting-Liquid Relative Permeability Measurement
Authors: Hartwig William H.
Published: December 2007

A paper by Rose has called attention to some of the problems of wetting-liquid relative permeability measurement. The premises and conclusions set forth by Rose, namely the applicability of the Hassler scheme of measurement, will be accepted. In addition, it will be concluded that certain electrical analog circuits can be used as a pattern for consideration of possible hydraulic systems of measurements.

New Scheme of Measurement

The object of this note is to propose a new scheme of wetting liquid relative permeability measurement. It is significantly different from those heretofore described, nonetheless it is based on Hassler concepts. The scheme is illustrated in Fig. 1 in terms of the corresponding electric circuit analog. It may be designated descriptively as the "comparison" method of wetting-liquid relative permeability measurement.

The resistance of the core sample is assumed small compared to the barrier resistances. This condition, it will be recalled, is a limitation of the methods discussed by Hassler and Rose but becomes an advantage in the method here proposed.

A complete transient analysis of this network is not necessary if the above conditions are observed. The equation for the battery current, in terms of the Laplacian operator, is given to illustrate the assumptions to be made.
Transmissivity and Diffusivity Mapping From Interference Test Data: A Field Example
Authors: Najurieta Humberto , Durán Rodolfo , Samaniego–V Fernando , Rodriguez Antonio , Martinez-Angeles Raymundo , Pérez Rosales Candelario
Published: December 2007

We present a method to obtain a 2D description of a reservoir in terms of transmissivity and diffusivity estimated from well testing. This technique is based on the averaging of the parameters in a proposed interference-test measurement area. This area depends on time, diffusivity, and pressure-gauge sensitivity. We discuss a field application in a heterogeneous, anisotropic reservoir, and we use a simulator that uses oil/water production data from a pilot water-injection test to validate the application's results.
Phase Splitting of Wet Steam in Annular Flow Through a Horizontal Impacting Tee
Authors: Chien Sze-Foo , Rubel Mark T.
Published: December 2007

Phase splitting occurs during gas/liquid two-phase flow through pipe junctions and causes a gas/liquid mass ratio in the outlet legs of the junction that is different from that at the inlet. In steamflood distribution networks, this results in different steam qualities at the outlets of a junction than at the inlet. This, in turn, results in a heat distribution not in accordance with the mass distribution in the outlets of the tee. Because heat management of a steamflood project is important for both economic incentives and ultimate recovery, phase splitting must be understood and controlled. This paper presents the results of an experimental investigation conducted on phase splitting of wet steam during annular flow through a horizontal 2-in. impacting tee. The experimental operating range included inlet pressures of 400 and 600 psig, inlet mass fluxes from 1, 180 to 10, 150 lbm/(in.2-hr), inlet steam qualities from 0.2 to 0.8, and outlet vapor extraction ratios for one outlet leg from 0.2 to 0.5. From these experimental data, the relative importance of these variables on phase splitting was determined and correlations to predict the outlet steam qualities were established. These correlations predicted the experimental results of the present investigation and of Azzopardi et al. to within acceptable limits.
The Effect of Fluid Diversion on the Acid Stimulation of a Perforation
Authors: Lea C. -M. , Hill A. D. , Sepehrnoori Kamy
Published: December 2007

A previously developed model that considers the effect of acidizing on the productivity of a single perforation penetrating a sandstone reservoir was extended to account for the effect of particulate diverting agents on acid distribution inside the perforation. Cases were run that simulate various types of formation damage, including damage from drilling-mud infiltration and damage caused by perforating itself. The model predicts the evolution of the perforation skin factor as acid dissolves formation minerals in the surrounding region. The primary result of this work is that, for the types of damage simulated, fluid diversion within a perforation has little effect on stimulation performance. Although the diverting agent significantly changes the acid distribution at the perforation surface, the acid tends to migrate rapidly to undamaged regions in the formation. This paper presents results from a series of case studies that emphasized the effect of fluid diversion inside a perforation.
Fracture Diagnostics With Tube Wave Reflection Logs
Authors: Medlin W.L. , Schmitt D.P.
Published: December 2007

The Tube-Wave Reflection Log (TWRL) is a new fracture diagnostic method that is based on cased-hole acoustic logging. It relies on reflection and attenuation effects in tube waves resulting from fluid flow through perforations into hydraulic fractures. Information about the location, conductivity, and height of fractures can be deduced from these effects.

Introduction

The TWRL uses low-frequency tube waves to detect and provide information about fractured intervals behind perforated casing. Tube waves are interface waves that propagate in unperforated casing with little attenuation at a speed roughly equal to the fluid compressional velocity. The TWRL concept relies on the sensitivity of tube waves to changes in wellbore-wall permeability. An increase in permeability causes an increase in attenuation and a decrease in velocity of the tube waves owing to fluid flow in and out of the permeable zone. These phenomena are well known.

A hydraulically induced fracture, in communication with a cased borehole through perforations, acts as a high-permeability zone in an otherwise impermeable wellbore. Throughout this zone, the tube waves are attenuated and slowed down owing to fluid flow into and out of the fracture. Tube-wave reflections also occur at the top and bottom of the fracture zone because of impedance contrasts.
Reservoir Performance of a Gravity-Stable, Vertical CO2 Miscible Flood: Wolfcamp Reef Reservoir, Wellman Unit
Authors: Bangia V. K. , Yau F. F. , Hendricks G. R.
Published: December 2007

A gravity-stable, vertical CO2 miscible flood was implemented in the Wellman Unit Wolfcamp reef reservoir in 1983. CO2 was injected into the crest of the reservoir to displace the oil vertically downward, and water was injected into the lower water-swept region of the reservoir to maintain reservoir pressure at slightly above the minimum miscibility pressure (MMP). Excellent production response to increased CO2 injection was observed. The reservoir performance was encouraging and indicated excellent volumetric conformance and ultimate recovery. This paper reviews the operating strategy and project performance from inception through mid-1991.
Effect of Cyclic Flow Interruptions on Performance of Vertically Directed Miscible Floods
Authors: Adamache Ion , Kantzas Apostolos , McIntyre Frank , Sigmund Philip M.
Published: December 2007

Spatial variation in permeability can result in a wide range of critical rates in heterogeneous carbonate reservoirs undergoing vertical miscible floods. Such situations provide an opportunity for new design strategies where gravity, viscosity, and forces are used to advantage to improve miscible flood performance. One such design strategy is use of cyclic interruptions in the form of well flow shut-in. Field observations and laboratory experiments are presented.
Exploration and Development of the Kutubu Project in Papua New Guinea
Authors: Chou C.K.
Published: December 2007

This paper describes the exploration and development of the Kutubu project, the first major oil development in Papua New Guinea. It presents a case study of how a broad range of interrelated development issues were addressed and resolved during planning to obtain an optimized development plan. The first oil from the Kutubu project was produced in mid-1992. So far, field performance is as anticipated.

Introduction

The Kutubu project discovery well was drilled in 1986. The treacherous terrain and lack of infrastructure in the remote Highlands area of Papua New Guinea where the project is located made development a challenging and costly proposition. The risk and cost of the project necessitated continuous reassessment of project viability based on a stream of new and often surprising appraisal-well data. Part of the process involved optimization of the depletion plan and facilities design concurrent with appraisal drilling. This integrated approach to development yielded an optimized development and shortened the time between discovery and production startup.

Besides the development approach, the Kutubu project is of general interest for other reasons. The Kutubu reservoirs are unique in many respects, resulting in a number of interesting reservoir issues, including the existence of a tilted oil/water contact (OWC). This paper discusses these technical issues and solutions to the development problems they pose.

Discovery of the Kutubu Reservoirs

Although the search for oil in Papua New Guinea began in the 1920's, the first significant deposits were not discovered until 1986, with the drilling of Well Iagifu-2X by Chevron Niugini as operator for a six-company joint venture (Chevron, British Petroleum, Ampolex, BH Petroleum, Oil Search, and Merlin). The discovery well was drilled in Petroleum Prospecting License 100 in the mountainous southern Highlands area. The oil pool discovered by Well Iagifu-2X, along with six smaller pools, make up the Kutubu project.
The Rock-Mechanical Aspects of Drilling a North Sea Horizontal Well
Authors: Wong S-W. , Veeken C. A. M. , Kenter C. J.
Published: December 2007

In view of the high cost of extended reach horizontal drilling, a borehole stability study was conducted to determine the range of mud weights suitable for drilling the first horizontal well in a North Sea oil field. The stability of the borehole was assessed using three methods that differ in complexity, cost, and conservatism. The study shows that drilling the horizontal section is feasible from a rock-mechanical viewpoint if a mud weight slightly above the pore pressure is used.
Ness Horizontal-Well Case Study
Authors: Koonsman T.L. , Purpich A.J.
Published: December 2007

This paper reviews the reservoir management work that led to the recommendation to drill the Ness field horizontal well. It also discusses the poor well performance seen almost immediately after production began and the reasons for that well performance revealed by a postdrill reservoir simulation. Finally, the atypical logging responses observed in the well are discussed.

Introduction

The Ness field has contributed significantly to the oil production volumes and revenue for the partners in the Mobil-operated Block 9/13 in the U.K. sector of the North Sea. When the horizontal well was drilled, the partners were Amerada Hess, Enterprise Oil, North Sea Holdings, and Mobil. The field was originally brought on stream in Aug. 1987 at a rate of 17,500 BOPD [2780 m3/d oil]. At the end of 1988, production rates began to decrease because of water production, which was thought to be caused by water coning. by Summer 1989, it was apparent that additional production wells had to be drilled to maintain a plateau production rate. Alternatively, the partnership would have to accept an extended production life associated with increasing water production rates production life associated with increasing water production rates and lower ultimate recovery.

The initial field development wells were drilled and completed with vertical-well technology. Both vertical and horizontal wells were considered for the additional wells. In particular, the expected performances of both well types were particular, the expected performances of both well types were compared on the basis of their impact on the long-term development program for Ness. program for Ness.

This paper addresses the reservoir management questions raised and decisions made that led to the recommendation to drill the Ness horizontal well. Further, explanations are offered for the causes of the unusual logging-tool responses seen in horizontal wells, specifically from measurement-while-drilling (MWD) technology.

Background

Discovery and Geologic Description. The Ness field was discovered in May 1986 by the Exploration Well 9/13b-28A (S28A), which encountered 152 ft [46.3 m] of hydrocarbon-bearing Beryl formation sandstone. It was later completed as a development well. A second development well, Well 9/13b-31Z (S31Z), was completed in Aug. 1987 and had 106 ft [32.3 m] of Beryl formation pay. Figs. 1 and 2 show the field and wells, respectively.
Geologic and Hydrologie Characterization of Coalbed-Methane Reservoirs in the San Juan Basin
Authors: Kaiser W. R. , Ayers W. B.
Published: December 2007

Fruitland coals are best developed in the north-central part of the San Juan basin. Coal distribution is controlled by shoreline and fluvial depositional settings. Hydraulic gradient, pressure regime, and hydrochemistry reflect regional permeability contrasts. The most productive (>1 MMcf/D) coalbed wells occur along a structural hinge line in association with a regional permeability barrier (no-flow boundary) at the basin center.
A Method of Predicting Revaporization of Retrograde Condensate by Dry-Gas Injection
Authors: Givens James W.
Published: December 2007

This paper presents a mathematical model for predicting the revaporization of retrograde predicting the revaporization of retrograde condensate liquid by dry-gas injection. The primary assumptions in the model are (1) that complete phase equilibrium exists between the gas and phase equilibrium exists between the gas and liquid in the model; (2) the liquid saturation is less than the mobile liquid saturation; and (3) that the dry gas does not bypass any rich gas as it sweeps through the model.

The model calculates the phase compositions and saturations for all 10 cells, liquid phase recovery, and produced gas composition as a function of cumulative injection.

The predicted results for two synthetic systems were found to agree favorably with the results of laboratory displacement studies. The systems investigated were a methane-normal pentane system and a sour system containing mainly methane, hydrogen sulfide, normal pentane, and normal heptane.

Introduction

The revaporization of retrograde liquid is a very important factor that must be considered in selecting the optimum operating procedure for a gas condensate reservoir. Some reservoirs may be cycled at pressures below their dew point without a significant loss of liquid recovery. In order to ascertain the revaporization characteristics for a reservoir, the reservoir fluids and available injection gases must be studied at reservoir temperature and the desired pressure levels. This type of laboratory study requires considerable time and expense; therefore, the mathematical model presented here was developed to reduce the time, presented here was developed to reduce the time, expense and laboratory work necessary to evaluate the revaporization process.
Comments on "Sailboats and Drilling Rigs" (H.D. Aggers)
Authors: Aggers H. D.
Published: December 2007

Comments on "Sailboats and Drilling Rigs"

The authors' interesting review of the case history of drilling in Corpus Christi Bay contains a real message for all of us who are concerned with urban oilfield development. Our industry's situation is very aptly stated by the remark on Page 452, "we do not become concerned or involved with a problem until it faces us in a blind alley", and "when positive actions by the frequently divergent and different interests start converging, there has to be either chaos or treaty."

Intelligent and workable regulations are necessary and can be obtained through joint action by oil company personnel, representatives of the people affected and members personnel, representatives of the people affected and members of responsible governmental agencies. It is not sufficient to depend upon petroleum industry information committees and oil company public relations people to adequately inform the general public of the advantages of orderly recovery of petroleum deposits under or near urban areas.
Analytical Development Of Vogel-Type Inflow Performance Relationships
Authors: Wiggins Michael L. , Russell James E. , Jennings James W.
Published: December 2007

In 1962, Vogel proposed an empirical inflow performance relationship (IPR) for solution-gas drive reservoirs based on numerical simulation results. This relationship is qoqo,max=1−0.2pwfp¯r−0.8(pwfp¯r)2

and was based on a wide range of rock and fluid properties. This generalized relationship gained almost immediate acceptance in the industry due to its relative ease of use and because it gave reasonable engineering accuracy. This paper presents a theoretical basis for Vogel's IPR based on the physical nature of the multiphase flow system. The resulting analytical IPR follows from a Taylor series expansion of the multiphase flow equations and is verified by computer simulation results.