bluuebunny/crossref_metadata_2025_split huggingface dataset:
Primary and Enhanced Recovery of Ekofisk Field: A Single- and Double-Porosity Numerical Simulation Study
Authors: da Silva F. V. 
Published: December 2007

ABSTRACT
This paper presents the successive modelling solutions used to estimate the performance under primary recovery as well as enhanced recovery of the Ekofisk Field, the giant oil field located in the Central Graben in the Norwegian Sector of the North Sea. The field consists of two separated highly fractured, high porosity chalky limestone reservoirs, initially overpressured and containing around 11.5 billion reservoir barrels of highly volatile reservoir fluids.
For first evaluation, primary recovery and waterflooding single porosity simulators have been used, the compositional behaviour of reservoir fluids being approximated by a partial density formulation. Fracture flow in this first approximation is simulated by using a set of pseudo-relative permeability curves previously generated for different fracture spacings, which in turn were correlated from core observation as a function of effective permeability. The generation of these pseudo-curves is described in the paper.
For secondary recovery, a dual porosity, 4 component, generalized black oil simulator was used, both for simulating waterflooding pilot tests and for predicting future waterflooding performance.
Finally, for the nitrogen injection feasibility study, a new compositional dual porosity, implicit simulator is being used, which includes special features such as fracture-to-matrix molecular diffusion and analytical solution for well hydraulics with automatic gaslift.
Drillstem Test Pressure Analysis Considering Several Flow Geometries and Reservoir Models
Authors: de Fatima e Silva M. L. , de Franca Corrèa A. C. 
Published: December 2007

ABSTRACT
Analysis of field data obtained from pressure transient testing, may not always be performed with methods based on plane radial flow.
A well is often subjected to physical conditions which may lead the flow phenomena to be better represented by different flow patterns, such as spherical flow (near wellbore effects in partially penetrating wells) or linear flow (short term tests in artificially fractured wells). Large-scale heterogeneities, which can be represented by faults or radial discontinuities in rock or fluid properties, may cause anomalous behaviour in wellbore pressure.
An approach which models a drillstem test (DST) as a changing wellbore storage problem1, originally developed for plane radial flow, has been extended to the following conditions which may affect short term testing: linear flow,spherical flow,well close to a linear sealing fault,radial flow in a composite reservoir.
New wellbore pressure equations for both flow and shut-in periods of drillstem tests have been derived. These equations have been used to develop new specialized methods for analysis of pressure buildup data of drillstem tests.
New derivative type curves, which may be employed for interpretation of drillstem test flow periods ("slug tests"), are also presented.
The method of Laplace transformation2 has been used to obtain the solutions described in this work. In some cases, inversion from Laplace spaced has been carried out numerically by standard algorithms.
Natural Water Influx in Nonsymmetric Reservoir/Aquifer Systems
Authors: Numbere D. T. 
Published: December 2007

ABSTRACT
A generalized method of calculating the dimensionless aquifer influx functions Q(tD) for linear, radial, as well as complex reservoir-aquifer geometries is presented. First, the method is described and validated by comparison with the analytical solutions of Van Everdingen and Hurst and Nabor and Barham for radial and linear systems respectively. Then the method is applied to calculate Q(tD) for radial but non-concentric, non-symmetric linear, and systems with irregular and complex geometries. One objective was to calculate what effect the shape of the aquifer inner boundary has on Q(tD). Several geometric shapes all having the same area were tested, such that each can be approximated by the same linear or radial shape. The results demonstrate that replacing regular and even irregular, symmetric or non-symmetric reservoir/aquifer boundary shapes by their approximately linear or radial equivalents introduces only minor error provided the real and approximate shapes are of similar length. Otherwise, large errors can be introduced. This technique provides a way to calculate the aquifer influx functions for reservoir-aquifer systems that are too complex to be reducible to simple linear or radial systems such as several oil reservoirs located within a common aquifer. This provides a useful tool for calculating water influx for systems where the necessary table of look-up values do not exist.
A Methodology To Quantify Uncertainties and Leveraging Issues in Oil and Gas Project Economics
Authors: Thompson R. R. 
Published: December 2007

Abstract
This paper describes a methodology by which economics for oil and gas projects can be analyzed to determine leveraging aspects and quantify unknowns. Discounted before-tax summaries from an economics program are processed to determine the effects that % changes in individual project components have on total project value. Ranges of uncertainty for each component are taken into account to determine the most leveraging elements in terms of net present value. The analysis is extended to include Monte Carlo simulation to quantify net present value, upside and downside values, chance of having an economic project, and downside net present value. An example problem is provided.
Gas Injection In City Of Inglewood Pool Inglewood Oil Field - California
Authors: Hedjazi A.K. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the 38th Annual California Regional Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Los Angeles, California, October 26 and 27, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
The City of Inglewood Pool gas injection project, Inglewood Oil Field, California provides a 3 year case history of successful gas injection operations in a depletion type reservoir producing 290 API oil.
The pool is a stratigraphic trap which pinches out abruptly upstructure. The structure dips about 300 at the crest, with dips of 600 on the flanks near the oil/water contact. The average depth to the top of the zone is 9,000 feet. The average porosity is 13.8% and the arithmetic average air permeabilities is 8.7 md. The reservoir had an original gas cap of approximately 7-1/2% of the total hydrocarbon reservoir pore volume.
The original reservoir pressure, estimated at 4,350 psia, had declined to 2,800 psia prior to initiating gas injection. Injection into 8 crestal well was initiated in February 1964 at 3,800 MCF/D and 3,000 psig. Approximately 1,400,000 MCF of gas had been injected into the pool when injection was increased to 6,000 MCF/D in September 1964. To date, 5,900,000 MCF of gas have been injected with a resulting average reservoir pressure increase of 475 psi to 3,275 psia.
Reservoir calculations indicated that only 12.5% of the original oil in place could be recovered by normal depletion, but that recovery could be increased to 22.8% by gas injection.
Current production is 820 B/D oil, which represents a gain of 580 B/D over normal depletion. Cumulative additional oil recovery to date is about 500,000 barrels.

Introduction
The Inglewood Oil Field is located about 10 miles southwest of the Los Angeles Civic Center (Figure 1). The City of Inglewood Zone is the next-to-deepest zone of eight major producing intervals in the field. The sand is of Upper Miocene age (Figure 2).
The City of Inglewood Pool, discovered in 1960, lies between 8,000 and 10,000 feet vertical depth. It contains 12 producing wells and 2 injection wells drilled on about 16-acre spacing. Dry gas injection was initiated in February 1964 and expended to full scale by September 1964.
The Ocean Odyssey: Well Control Project II
Authors: Gillespie J. D. , Wann K. E. 
Published: December 2007

Abstract
On September 22, 1988, a blowout occurred on the semi-submersible "Ocean Odyssey" in the UK sector of the North Sea. This paper will detail the uncertainties faced by the blowout control team when planning the abandonment of this well and describe some of the novel techniques implemented in this project. This case history shows that direct wellbore intervention into a subsea blowout can be an effective well control method.
Practical Application of Real-Time Expert System for Automatic Well Control
Authors: Lloyd G. M. , Bode D. J. , Nickens H. V. , Varnado S. G. 
Published: December 2007

ABSTRACT
Expert systems are receiving widespread interest in many fields. One critical application in the drilling industry that is ideally suited to use this technology is automated well control. In some drilling situations, particularly slim hole drilling, the reaction time between detection of a kick and the need to take corrective action may be only a fraction of a minute. In this application, a significant amount of data must, be continuously collected, processed, and analyzed in a short period of time. Expert systems can automate these functions.
This paper describes the design, development, and testing of an expert system for well control (XWC) on a slim hole drilling rig. The use of an expert system operating in real time to perform complex analysis of the drilling data from rig sensors can significantly reduce false alarm rates as well as the probability of a small kick developing into an uncontrolled situation. The system is unique in several ways. First, it operates in real time. It samples flow in, flow out, and other parameters, processes the data, and transfers the information to the expert system. Second, the system can be classified as a true hybrid system in that extensive algorithmic calculations and models are incorporated where necessary. Finally, the entire system has been validated in a test well.
Field Evaluations Confirm Superior Benefits of MMLHC Fluid System on Hole Cleaning, Borehole Stability, and Rate of Penetration
Authors: Burba J. L. , Tehan W. F. , Hamilton F. D. , Holman W. E. , Porzucek C. , Christenson C. P. , McKenzie J. 
Published: December 2007

ABSTRACT
Over the last several years, the Dow Chemical Company and Westbridge Oilfield Products have been developing a novel drilling fluid system based on mixed metal layered hydroxide (MMLHC) chemistry. Among the significant advantages that these compounds provide is unparalleled solids suspension capabilities arising from a gel structure that breaks very easily and recovers rapidly. Conventional rheological models do not adequately describe the rheology of this system. Thus, a number of unconventional measurements, based on material science considerations have been utilized to develop a working rheological model from which effects of the fluid on drilling rate, bit usage, hole stability, and drilling fluid cost can be projected.
U.S. Demand For Atomic And Conventional Energy By 1982 A 15-Year Forecast With Emphasis On Petroleum
Authors: Lichtblau John H. 
Published: December 2007

1967 California Regional Meeting, Oct. 26–27, 1967 Los Angeles, CA.
I have taken as my assignment the outlook for all energy sources over the next 15 years, with particular emphasis on the impact of atomic energy on fossil fuels, especially petroleum. I've limited myself to a 15-year forecast because I believe this is the longest period for which it is reasonable to assume no major commercial impact from new technological developments except those already visible, at least in embryonic form, at the beginning of the period. Thus, the only new forms of energy sources or energy uses of economic significance by 1982 will be those whose commercial potential is already fairly well recognized today. By the same token, none of the significant energy sources and uses of today are likely to have disappeared by the end of our forecast period. In short, while our 15-year limit may render our outlook a bit less glamorous than the exciting forecasts of life and technology in the 21st century so frequently heard these days, it also avoids the snares and pitfalls of a soaring imagination, particularly if one takes as one's inspiration the phenomenal and historically unique technological progress of tile last 100 years. Looking ahead to 1982, it seems clear that the principal new development in the U.S. energy sector will be the dynamic growth of atomic energy. This growth has been predicted ever since that "Day of a Thousand Suns" back in June 1945.
Jackups for the Nineties: What Should the Industry Expect?
Authors: Springett C. N. 
Published: December 2007

ABSTRACT
Despite the prolonged downturn in the offshore drilling industry, there may be room for cautious optimism with respect to some specialized segments of the marketplace. The most interesting, and in many ways most challenging area, concerns the move towards bigger and more sophisticated jack-ups in deep water, harsh environments. This paper describes the challenge in terms of the technical and regulatory requirements but emphasizes the spirited discussions currently underway throughout the industry concerning the most appropriate way to make site specific structural assessments of jack-ups.
Although reference is made to "Galaxy I," a new super jack-up under construction in Singapore for Santa Fe, the primary thrust of the paper is to describe what an operator should be able to expect from the new generation of large jack-ups in the nineties. Performance is defined in terms of environmental capability, the analysis techniques used to validate the design and the equipment and configuration necessary to satisfy both efficient production drilling in the cantilever or skid-off mode and deep high pressure wild-cat drilling.
Maximum Movement of the Drilling Riser
Authors: Movsumov A. A. , Tagiev A. H. 
Published: December 2007

ABSTRACT
When disconnected, the drilling riser (even without buoancy modules) can collide with different parts of & moonpool and the floating rig itself. The collision may result in severe damage of the telescopic joint, and extra bending stresses. Calculations were made to find out the maximum movement (upward and lateral) of the disconnected riser as a function of the initial, vertical force applied to the riser.
Using the same approach, bending stresses due to rig heave with a riser, connected to the wellhead, are being investigated.
Prediction of Steamflood Performance in Heavy Oil Reservoirs Using Correlations Developed by Factorial Design Method
Authors: Chu C. 
Published: December 2007

ABSTRACT
By using the factorial design method, statistically significant correlations have been developed which enable one to predict steamflood performance in terms of project life, oil recovery and cumulative steam-oil ratio. The effects of various reservoir rock and fluid properties and steamflood design and operating variables on steamflood performance were discusssed.
Evaluation of Radioactive Tracer Surveys for Steam Injection Wells
Authors: Griston S. 
Published: December 2007

ABSTRACT
The proper distribution of steam over the injection zone is critical to the efficient operation of a steamflood project. Many factors affect downhole steam distribution, such as differences in relative injectivity between perforations and gravity segregation of the phases. Surveys can be run in the wellbore to determine the steam injection profile. These profiles can then indicate which parts of the reservoir have been steamed and which may have been bypassed.
Because steam consists of liquid and vapor phases, running profile surveys and interpreting the results are not straightforward. These surveys must be designed to generate information about the flow of both phases. Additionally, the survey results must be interpreted with a knowledge about the characteristics of the two-phase flow. In recent years, radioactive tracer surveys have become the most common method used to obtain steam profiles. The main emphasis has been on the use of inert radioactive gases for vapor profiling. Although radioactive tracer surveys are commonly used to obtain water or gas injection profiles, little is known about the reliability and accuracy of applying this method to profiling steam injection wells.
This paper presents the results of field testing and evaluation of vapor phase profile surveys using radioactive Krypton and Xenon gas tracers. Emphasis is given to surveying (or logging) procedures and data analysis methods and to determining the reliability and accuracy of vapor injection profiles. Existing data analysis and interpretation methods are reviewed and a new, automated method is presented that gives more consistent and reliable evaluation of tracer measurements. The accuracy of tracer measurements and resulting vapor injection profiles are discussed. Factors affecting repeatability of tracer measurements, such as tracer radiation intensity, wellhead steam conditions, and well completion are also discussed.
Current Practice in the Interpretation of Microfrac Tests in Oil Sands
Authors: Proskin S. A. , Scott J. D. , Chhina H. S. 
Published: December 2007

Abstract
Small volume hydraulic fracture tests, defined as microfrac tests, are conducted to determine the in situ principal stresses in oil formations. Interpretation difficulties arise when the tests are conducted in relatively shallow, unconsolidated sands which are typical of the oil sand deposits in Alberta, Canada. Interpretation methods for such tests are outlined and their use is discussed. Three microfrac case histories in the Athabasca oil sands deposit are presented and analyzed. Recommendations are given for performing microfrac tests in these formations.
Synthetic Polymer Developed for Cement Fluid-Loss Control
Authors: Strange A. F. , Brothers L. E. 
Published: December 2007

Abstract
A new fluid loss additive has been developed for a broad range of applications. A synthetic polymer has been used to control fluid loss values to meet specific requirements in the design of lightweight, standard-weight, and heavyweight slurries at circulating temperatures from 180°F to 400°F. Polymer-containing slurries mixed with fresh water, sea water, and water containing potassium chloride or sodium chloride (up to saturation) exhibit fluid loss values as low as 20 cc/30 min within these temperature ranges.
Various methods of determining fluid loss at temperatures above 190°F are utilized within the industry. These methods are explained and compared. The new additive does not have a pronounced affect on cement slurry viscosity. Slurries may be formulated to have low fluid loss values while being neither overly-viscous nor overly-dispersed. Such properties permit displacement without undue friction pressure at reasonable annular velocities, thus helping improve displacement mechanics and ensure efficient drilling fluid removal.
Results of using this polymer have been to help improve the probability of obtaining a successful cement job by (1) minimizing the risk of bridging, (2) enhancing displacement mechanics, and (3) providing early casing protection. Field case histories are provided.
Development of Sockeye Field in Offshore California: A Case History
Authors: Sankur V. , Weber L. S. , Masoner L. O. 
Published: December 2007

Abstract
Sockeye Field, discovered in 1970, lies offshore California in the Santa Barbara Channel. The decision to develop the field was made in 1983 based on 1979–83 exploration drilling. Platform Gail was installed in 1987 and development drilling commenced in June 1988. Currently there are eleven development wells with plans for two more (two duals and eleven single completions).
This project has taken 20 years to reach the development stage since the lease sale in 1968. This long time span was partly due to permitting delays encountered in offshore California projects and a Santa Barbara Channel drilling moratorium in the 1970's.
The field produces from five reservoirs; Middle and Upper Sespe Sands, Lower and Upper Topanga Sands, and the Monterey Formation. Sespe Sands are fluvial channel deposits with individual sand bodies with limited areal extents. The Middle Sespe produces dry sweet gas and the Upper Sespe produces sweet 29° API gravity oil. The Topanga Sands were deposited in a near shore environment and are more continuous in nature. Lower Topanga Sands contain sweet oil whereas Upper Topanga Sands test a low gravity 18° API sour oil. The Monterey Formation is composed of thin beds of cherts, porcellanites, siliceous shales, mudstones, and dolostones. The fractured Lower Monterey produces heavy sour oil, similar to that of the Upper Topanga.
To minimize risk, delineation wells were drilled early in the development program to ensure that reserves warranted additional investment in wells and facilities. Nine wells were completed during the first phase of the drilling program. Gas production from these wells was projected to exceed the capacity of the Carpinteria Gas Plant. The drilling rig was put on standby to evaluate various facilities modifications to handle production. At the conclusion of the evaluation, drilling was resumed with plans to drill four more wells.
Reservoir information was obtained through an integrated program of formation evaluation, core analysis, production logging and build-up and interference testing.
Hot Waterflood in a Post-Steamflood Reservoir: A Case History in the Kern River Field, California
Authors: Dorna R. G. 
Published: December 2007

Abstract
Texaco converted 275 steam displacement patterns to hot waterflood pilots in the Kern River Field. This test program was designed to evaluate hot water injection as a viable recovery mechanism in a post steamflood reservoir.
Response to hot water injection was typified by a decline in oil production and a corresponding increase in water production. Investigation into the reservoir rock and fluid properties indicated that a mobility ratio of 3.8 in combination with a highly permeable sand and steam desaturated area would not allow the formation of an effective immiscible displacement bank. The monitoring program demonstrated that oil resaturation occurred in areas where the injection water filled the steam desaturated zone. Temperature data from observation wells showed that hot water was ineffective at transferring heat to the reservoir.