bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

SummaryWe 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

Summary
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

SummaryA 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

Summary
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

Summary
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

Summary
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

Summary
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

SummaryIn 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

Summary
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

Summary
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 (&gt;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

Abstract
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

Abstract
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.
Determination of Gas Well Stabilization Factors in the Hugoton Field
Authors: Mathur Shri B. 
Published: December 2007

On the basis of a 72-hour shut-in pressure as an average reservoir pressure, the method described here can be applied satisfactorily pressure, the method described here can be applied satisfactorily to determine the stabilization factors for different wells in the Hugoton field, and in fact for wells in any tight, dry-gas, low-pressure reservoir.

Introduction
The stabilization factor can be defined as the ratio of a well's performance under pseudo-steady state conditions to the well's performance at the end of a given length of flowing time. When a gas well is drilled, it is necessary to predict the stabilized performance of each well for the orderly exploitation of gas reserves, future availabilities of gas, future gas contracting requirements and future planning of operating facilities. When a gas well is producing from a highly permeable reservoir, only a short period of time is required for steady-state conditions to be approximately established throughout the drainage area. Low permeability reservoirs exhibit "slow stabilization" and require long periods of flow and shut-in time for determination of stabilized conditions.
The conventional way to determine the stabilization factor for wells in the Hugoton fields of Kansas, Oklahoma and Texas is to shut in the well, which was previously flowing at stabilized conditions, for previously flowing at stabilized conditions, for maximum pressure buildup. The ratio of pressure buildup at the end of 72 hours compared with the maximum pressure buildup is then designated as the stabilization pressure buildup is then designated as the stabilization factor for that well. This requires that the well be shut in long enough for maximum pressure buildup, which may take a month or more.
Because there are hundreds of wells in the Hugoton fields on which it is not practical to conduct long buildup tests, a method is needed for determining stabilization factors based on information obtained from short term shut-in tests.
The objectives of this paper are (1) to present a theoretical development of a method of determining the stabilization factor from short term tests; (2) to present an application of the developed (3) theory to field present an application of the developed theory to field data; (4) to verify its validity by comparing the results with those obtained by the conventional long duration buildup method; and (5) to determine if the stabilization time and hence the stabilization factor changes during the life of a well.
Mathematical Description of the Method
The solution for the diffusivity equation frequently used for a true infinite medium has been referred to as the point-source solution and can be expressed as a logarithmic function.
which may be rearranged to read
where
k= ln ------ + 0.809, crw2
JPT
P. 1101
Identification of Aluminum Scale With the Aid of Synthetically Produced Basic Aluminum Fluoride Complexes
Authors: Shuchart C. E. , Ali S. A. 
Published: December 2007

Summary
Aluminum scaling can be a problem following HF acidizing. In this paper, a series of synthetic aluminum scales was prepared and identified. The aluminum compounds of a field scale were identified with similar procedures. Recent field work showed that the use of acetic acid in the HF acidizing sequences significantly decreased scaling. The role of acetic acid is discussed on the basis of laboratory support of these field data.
A Deepwater Riser Emergency Disconnect Antirecoil System
Authors: Hock C.J. , Young R.D. 
Published: December 2007

Summary
During drilling in deep water, very high tensions must be used to control the riser, so a large amount of energy is stored in the riser and tensioning system. If the riser and stored energy are not controlled during an unplanned disconnect of the riser from the subsea blowout preventer (BOP), which would result if a dynamically positioned vessel drifted off location, the rig could be seriously damaged and the costly riser could be lost. This paper presents the design processes, installation, and testing of the riser emergency disconnect antirecoil system added to the drillship Discoverer 534 as part of the upgrade to 6,000-ft water depth. The system controls the riser and its tensioning system during and after an unplanned disconnect. This paper views the initial design analysis of the riser and tensioning system using an existing computer modeling program. It presents modifications to the computer program to simulate a disconnect with mud in the riser and using the telescopic-joint latching riser capture system. We discuss the hardware and the problems experienced during the design and computer analysis phases and their unique solutions. We describe important details of the installation in the shipyard and during sea trials. We discuss the full-scale instrumented emergency-disconnect test of the system in 3,700 ft of water and the results of the test. Finally, we present the post-test fine tuning of the computer modeling and predictions for deepwater/high-mud-weight disconnects.

Introduction
When the upgrade of Discoverer 534 to drill in 6,000 ft of water in the Gulf of Mexico began, knowledge gained during years of record-setting deepwater drilling by the Discoverer Seven Seas was used in guiding the project. Engineering studies made during the upgrading of the Discoverer Seven Seas indicated that a riser antirecoil system was needed to control the riser during and after an unplanned disconnect from the subsea BOP. Control of the energy stored in the marine riser and its tensioning system was necessary to latch it to the floating vessel mechanically, thereby preventing riser loss.
The Discoverer 534 and the Discoverer Seven Seas are sister drillships with essentially the same hull. However, their riser and riser tensioning systems are different. The Discoverer Seven Seas has an 18 5/8-in.-OD riser system; the Discoverer 534 has a 21 in.-OD riser. The type of drilling planned for the Discoverer 534 called for heavy weight drilling fluids of up to 16 lbm/gal. The Discoverer Seven Seas typically used much lighter muds. These differences meant that, while the experience gained from operating the Discoverer Seven Seas would be invaluable, the engineering and the design of its antirecoil system could not be directly applied to the Discoverer 534. With the Discoverer Seven Seas as a starting point, the design of the Discoverer 534 began.